20-F 1 a05-17375_120f.htm 20-F

As filed with the Securities and Exchange Commission on October 7, 2005.

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, DC 20549

FORM 20-F

(Mark One)

o Registration statement pursuant to Section 12(b) or 12(g) of the Securities Exchange Act of 1934

ý Annual report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the fiscal year ended December 31, 2003

o Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934

For the transition period from to

Commission File No. 001-12142

PETRÓLEOS DE VENEZUELA, S.A.
(Exact Name of Registrant as Specified in Its Charter)

Venezuelan National Petroleum Company		Bolivarian Republic of Venezuela
(Translation of Registrant’s Name into English)		(Jurisdiction of Incorporation or Organization)

Avenida Libertador, La Campiña, Apdo. 169, Caracas 1010-A, Venezuela
(Address of Principal Executive Offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act: None.

Securities registered or to be registered pursuant to Section 12(g) of the Act: None.

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

PDVSA Finance Ltd. 6.650% Notes due 2006	PDVSA Finance Ltd. 9.375% Notes due 2007
PDVSA Finance Ltd. 6.800% Notes due 2008	PDVSA Finance Ltd. 9.750% Notes due 2010
PDVSA Finance Ltd. 8.500% Notes due 2012	PDVSA Finance Ltd. 7.400% Notes due 2016
PDVSA Finance Ltd. 9.950% Notes due 2020	PDVSA Finance Ltd. 7.500% Notes due 2028

Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 51,204 shares of the common stock of PETRÓLEOS DE VENEZUELA, S.A. were outstanding as of December 31, 2003.

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes

Indicate by check mark which financial statement item the registrant has elected to follow.

Item 17

Item 18

If this is an annual report, indicate check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). which financial statement item the registrant has elected to follow.

Yes

TABLE OF CONTENTS

Table of Contents

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

FACTORS AFFECTING FORWARD-LOOKING STATEMENTS

PART I

Item 1.	Identity of Directors, Senior Management and Advisers
Item 2.	Offer Statistics and Expected Timetable
Item 3.	Key Information
Item 4.	Information on the Company
Item 5.	Operating and Financial Review and Prospects
Item 6.	Directors, Senior Management and Employees
Item 7.	Major Shareholders and Related Party Transactions
Item 8.	Financial Information
Item 9.	The Offer and Listing
Item 10.	Additional Information
Item 11.	Quantitative and Qualitative Disclosures about Market Risk
Item 12.	Description of Securities Other than Equity Securities

PART II

Item 13.	Defaults, Dividend Arrearages and Delinquencies
Item 14.	Material Modifications to the Rights of Security Holders and Use of Proceeds
Item 15.	Controls and Procedures
Item 16.	[Reserved]
Item 16A.	Audit Committee Financial Expert
Item 16B.	Code of Ethics
Item 16C.	Principal Accountant Fees and Services
Item 17.	Financial Statements
Item 18.	Financial Statements
Item 19.	Exhibits

ANNEX A

INCORPORATION OF CERTAIN DOCUMENTS BY REFERENCE

With respect to our obligations as co-registrant of PDVSA Finance Ltd.’s 6.650% Notes due 2006, 9.375% Notes due 2007, 6.800% Notes due 2008, 9.750% Notes due 2010, 8.500% Notes due 2012, 7.400% Notes due 2016, 9.950% Notes due 2020 and 7.500% Notes due 2028 (collectively, the “PDVSA Finance Notes”), PDVSA Finance Ltd.’s annual report on Form 20-F for the year ended December 31, 2003, as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-09678) on October 7, 2005 is incorporated herein by reference.

FACTORS AFFECTING FORWARD-LOOKING STATEMENTS

This annual report on Form 20-F contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. Specifically, certain statements under the caption “Item 4.B. Business overview” and under the caption “Item 5. Operating and Financial Review and Prospects” relating to the expected results of exploration, drilling and production activities, refining processes, petrochemicals, gas, Orimulsion® and coal activities, and related capital expenditures and investments, the expected results of joint venture projects, the anticipated demand for new or improved products, environmental compliance and remediation and related capital expenditures, sales, taxes, dividends and contributions to Venezuela, are forward-looking statements. Words such as “anticipate,” “estimate,” “prospect” and similar expressions are used to identify forward-looking statements. Forward-looking statements are subject to risks and uncertainties related to Venezuelan and international markets, inflation, the availability of continued access to capital markets and financing on favorable terms, regulatory compliance requirements, changes in import controls or import duties, levies or taxes and changes in prices or demand for our products as a result of actions of our competitors or economic factors. Those statements are also subject to the risks of costs and anticipated performance capabilities of technology, and performance by third parties of their contractual obligations. Exploration activities are subject to risks arising from the inherent difficulty of predicting the presence, yield and quality of hydrocarbon deposits, as well as unknown or unforeseen difficulties in extracting, transporting or processing any hydrocarbons found or doing so on an economic basis. Should one or more of these risks or uncertainties materialize, actual results may vary materially from those estimated, anticipated or projected. Specifically, but without limitation, capital costs could increase, projects could be delayed, and anticipated improvements in capacity or performance may not be fully realized. Although we believe that the expectations reflected by such forward-looking statements are reasonable based on information currently available, readers are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this annual report. We undertake no obligation to publicly release any revision to these forward-looking statements to reflect events or circumstances after the date of this annual report.

The annual report on Form 20-F of PDVSA Finance Ltd., our wholly-owned subsidiary, for the year ended December 31, 2003 incorporated by reference herein also contains forward-looking statements. For a discussion of the factors affecting these statements contained in PDVSA Finance’s annual report, see “Factors Affecting Forward-Looking Statements” on page 1 thereof.

As used in this annual report, references to “dollars” or “$” are to the lawful currency of the United States and references to “bolivars” or “Bs” are to the lawful currency of Venezuela. A unit conversion table and a glossary of certain oil and gas terms, including abbreviations for certain units, used in this annual report are contained in Annex A. When used in this annual report, the term “Petróleos de Venezuela” refers to Petróleos de Venezuela, S.A. and the terms “we,” “our,” “us,” “the Company” and “PDVSA” refer to Petróleos de Venezuela, S.A. and its consolidated subsidiaries.

Other miscellaneous terms

Unless the context indicates otherwise, the following terms have the meanings shown below:

“Amerada Hess” – Amerada Hess Corporation

“BCV” – Banco Central de Venezuela

“Bitor” – Bitúmenes Orinoco, S.A.

“BOPEC” – Bonaire Petroleum Corporation N.V.

“BORCO” – The Bahamas Oil Refining Company International Limited

“BP” – British Petroleum

“BP RP” – British Petroleum Refining & Petrochemical GmbH

“Carbozulia” – Carbones del Zulia, S.A.

“Chalmette Refining” – Chalmette Refining, L.L.C.

“ChevronTexaco” – ChevronTexaco Corporation

“CIED” – Centro Internacional de Educación y Desarrollo

“CITGO” – CITGO Petroleum Corporation

“CITGO Latin America” – CITGO International Latin America, Inc.

“ConocoPhillips” – ConocoPhillips

“CVP” – Corporación Venezolana del Petróleo, S.A.

“Deltaven” – Deltaven, S.A.

“ExxonMobil” – ExxonMobil Corporation

“FEM” – Fondo para la Estabilización Macroeconómica (Macroeconomic Stabilization Fund)

“FONDESPA” – Fondo para el Desarrollo Económico y Social del País

“Fortum Oil and Gas” – Fortum Oil and Gas OY

“Hovensa” – Hovensa, L.L.C.

“ENI” – Eni B.V.

“Intevep” – Intevep, S.A.

“Isla Refinery” – Refinería Isla (Curaçao), S.A.

“Lyondell” – Lyondell Petrochemical Corporation

“LYONDELL-CITGO” – LYONDELL-CITGO Refining Company, L.P.

“Merey Sweeny” – Merey Sweeny, L.P.

“Neste Oil Corporation” – Neste Oil

“Nynäs” – AB Nynäs Petroleum

“OPEC” – Organization of Petroleum Exporting Countries

“PDV America” – PDV America, Inc.

“PDV Chalmette” – PDV Chalmette, Inc.

“PDV Europa” – PDV Europa B.V.

“PDV Holding” – PDV Holding, Inc.

“PDV Marina” – PDV Marina, S.A.

“PDVMR” – PDV Midwest Refining, L.L.C.

“PDV VI” – PDVSA Virgin Island, Inc.

“PDVSA Cerro Negro” – PDVSA Cerro Negro, S.A.

“PDVSA Finance” – PDVSA Finance Ltd.

“PDVSA Gas” – PDVSA Gas, S.A.

“PDVSA Petróleo” – PDVSA Petróleo, S.A.

“PDVSA Sincor” – PDVSA Sincor, S.A.

“PDVSA-P&G” – PDVSA Petróleo y Gas, S.A.

“Pequiven” – Petroquímica de Venezuela, S.A.

“Petrozuata” – Petrolera Zuata, C.A.

“Phillips Petroleum” – Phillips Petroleum Corporation

“Ruhr” – Ruhr Oel GmbH

“SEC” – Securities and Exchange Commission

“Statoil” – Statoil Sincor AS

“Total Fina” – Total Fina Venezuela, S.A.

“Veba Oel” – Veba Oel AG

“Venezuela” – The Bolivarian Republic of Venezuela

PART I

Item 1. Identity of Directors, Senior Management and Advisers

Not Applicable.

Item 2. Offer Statistics and Expected Timetable

Not Applicable.

Item 3. Key Information

3.A Selected financial data

The selected data presented below for, and as of the end of, each of the years in the five-year period ended December 31, 2003, are derived from the audited consolidated financial statements of PDVSA. See “Item 18. Financial Statements.”

	At or for the Year Ended December 31,
	2003		2002		2001		2000		1999
	($ in millions)
Income Statement Data:
Sales of crude oil and products
Exports and international markets	44,178		39,875		42,682		49,780		30,369
In Venezuela	961		1,236		1,701		2,230		1,450
Petrochemical and other sales	1,071		1,201		1,403		1,224		781
Net sales	46,210		42,312		45,786		53,234		32,600
Equity in earnings of non-consolidated investees	379		268		464		446		48
Total revenues	46,589		42,580		46,250		53,680		32,648
Total costs and expenses	41,400		39,073		37,977		40,029		26,636
Operating income	5,189		3,507		8,273		13,651		6,012
Financing expenses	627		763		509		672		662
Income before income taxes and minority interests and cumulative effect of accounting change	4,562		2,744		7,764		12,979		5,350
Provision for income taxes	(1,602	)	(149	)	(3,766	)	(5,748	)	(2,521	)
Minority interests	(6	)	(5	)	(5	)	(15	)	(11	)
Income before cumulative effect of accounting change	2,954		2,590		3,993		7,216		2,818
Cumulative effect of accounting change for the cost of asset retirement obligations	(234	)	—		—		—		—
Net income	2,720		2,590		3,993		7,216		2,818
Balance Sheet Data:
Cash and cash equivalents	2,938		1,703		925		3,257		1,079
Notes and accounts receivable	4,955		3,515		3,280		4,435		3,820
Total assets	55,355		54,939		57,200		57,600		49,990
Current portion of long-term debt(1)	750		1,817		1,000		596		910
Long-term debt and capital lease obligations (excluding current portion).	6,265		6,426		7,544		7,187		7,892
Stockholder’s equity	37,418		37,288		37,098		37,932		32,894
Capital stock	39,094		39,094		39,094		39,094		39,094
Other Financial Data:
Net cash provided by operating activities	5,746		4,880		6,965		10,285		4,633
Net cash used in investing activities	(902	)	(1,226	)	(5,263	)	(5,360	)	(3,326	)
Net cash used in financing activities	(3,609	)	(2,836	)	(4,034	)	(2,747	)	(913	)
Capital expenditures	1,969		2,743		3,781		3,185		3,041
Depreciation and depletion	2,824		3,038		2,624		3,001		2,821
Debt/Equity(2)	19	%	22	%	23	%	21	%	27	%
Total payments to shareholder	9,585		9,474		12,097		11,641		6,549
Dividends(3) (5)	2,326		2,652		4,862		1,732		1,719
Production tax	5,944		5,911		3,792		4,954		2,654
Income taxes(4)	1,315		911		3,443		4,955		2,176

(1) Excludes current portion of capital lease obligations, which amounted to $20 million, $30 million, $62 million, $122 million and $117 million in 2003, 2002, 2001, 2000 and 1999, respectively.

(2) Calculated as total debt (long-term debt, including current portion of long-term debt and capital leases) divided by stockholder’s equity.

(3) During 1999, special tax recovery certificates, or CERTs, amounting to $1,291 million were used to pay dividends.

(4) During 2001, 2000 and 1999, we used CERTs amounting to $84 million, $255 million and $22 million, respectively, to pay income taxes.

(5) During 2003, $251million of trade notes receivable were distributed as a dividend.

	At or for the Year Ended December 31,
	2003			2002			2001			2000			1999
	(MBPD, unless otherwise indicated)
Operating Data:
Production
Condensate	22			46			48			50			43
Light crude oil (API gravity of 30° or more)	727			774			1,135			1,174			1,189
Medium crude oil (API gravity of between 21° and 30°)	914			962			1,018			1,047			1,095
Heavy crude oil (API gravity of less than 21°)	788			877			893			814			623
Total crude oil	2,451			2,659			3,094			3,085			2,950
Liquid petroleum gas	144			173			173			167			177
Total crude oil and liquid petroleum gas	2,595			2,832			3,267			3,252			3,127
Net natural gas (MMCFD)(1)	3,432			3,672			4,093			3,979			3,766
Total crude oil, liquid petroleum gas and net natural gas (BOE)(2)	3,187			3,464			3,973			3,938			3,776
Sales volumes exported
Exports of crude oil with 30° or greater API	657			672			659			716			1,010
Exports of crude oil with less than 30° API	991			1,092			1,406			1,282			913
Exports of refined petroleum products	502			647			697			825			861
Total	2,150			2,411			2,762			2,823			2,784
Average export prices per unit ($ per barrel)
Exports of crude oil with 30° or greater API	$	27.16		$	23.46		$	22.47		$	28.20		$	17.08
Exports of crude oil with less than 30° API	$	22.56		$	20.24		$	17.29		$	23.12		$	13.45
Exports of refined petroleum products	$	26.53		$	24.23		$	23.94		$	28.40		$	17.80
Weighted average export prices(3)	$	24.89		$	21.94		$	20.21		$	25.91		$	16.04
Average production costs ($ per BOE)
Production cost per BOE of production, excluding operating service agreements(4)	$	2.06		$	2.42		$	2.17		$	2.22		$	2.00
Production cost per BOE of production (4)	$	3.85		$	3.92		$	3.38		$	3.48		$	2.72
Depreciation and depletion cost per BOE of production	$	0.53		$	0.54		$	0.38		$	0.46		$	0.37

Proved reserves(5)
Crude oil (MMB)
Condensate	1,919			1,900			1,723			1,772			1,847
Light crude oil (API gravity of 30° or more)	10,078			10,012			10,345			10,244			10,258
Medium crude oil (API gravity of between 21° and 30°)	12,340			12,450			12,891			12,804			12,195
Heavy crude oil (API gravity of between 11° and 21°)	17,617			17,414			17,266			17,177			16,861
Extra-heavy crude oil (API gravity of less than 11°)(6)	35,186			35,381			35,558			35,688			35,701
Total crude oil	77,140			77,157			77,783			77,685			76,862
Of which, relating to Operating Service Agreements(7)	5,446			5,501			5,600			5,479			5,450
Natural gas (BCF)(8)	150,043			147,109			148,295			147,585			146,611
Proved reserves of crude oil and natural gas (MMBOE) (6)	103,009			102,521			103,351			103,131			102,140
Remaining reserve life of proved crude oil reserves (years)(9)	74		x	70		x	64		x	64		x	70		x
Net crude oil refining capacity (MBPD) (10)
Venezuela (including Isla Refinery)	1,628			1,628			1,628			1,620			1,620
United States	1,205			1,205			1,205			1,198			1,224
Europe	259			252			252			252			252
Total	3,092			3,085			3,085			3,070			3,096

(1) Amounts indicated are net of natural gas used for reinjection purposes.

(2) Natural gas is converted to barrels of oil equivalent (BOE) at a ratio of 5.8 thousand cubic feet of natural gas per one barrel of crude oil.

(3) Weighted average sales price of crude oil, refined petroleum products and liquid petroleum gas exports.

(4) Calculated by dividing total costs (excluding depreciation and depletion) and expenses of crude oil, natural gas and liquid natural gas producing activities by total crude oil, liquid petroleum gas and net natural gas (BOE) produced.

(5) Proved reserves include both proved developed and undeveloped reserves.

(6) Proved reserves of extra-heavy oil located in the Orinoco Belt have a low development grade. Of the total gross proved reserves to be exploited under our Orinoco Belt project at December 31, 2003, approximately 10,483 MMB reserves are being developed under four association agreements in which PDVSA has an equity interest of less than 50%. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects.”

(7) Includes portion of proved crude oil reserves in fields relating to operating service agreements as of December 31 of the year in which each of such agreements went into effect. Such agreements may not necessarily result in the exploitation of 100% of these reserves during their term. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

(8) Includes 12,427 BCF, 12,454 BCF, 12,476 BCF, 12,505 BCF and 12,400 BCF in each of 2003, 2002, 2001, 2000 and 1999, respectively, associated with extra-heavy crude oil reserves.

(9) Based on crude oil production from the top of wells for each period and total proved crude oil reserves at the end of each period. Proved reserves of extra-heavy crude oil are substantially undeveloped. Proved reserves of extra-heavy crude oil in the Orinoco Belt are being developed in association with third parties. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects.”

(10) Amounts represent PDVSA’s interest in the refining capacity of all refineries in which it holds an equity or leasehold interest. See “Item 4.B Business overview—Refining and Marketing.”

Exchange rates

The following table sets forth certain information concerning the exchange rate of the bolivar to the dollar based on daily rates of exchange established by the BCV pursuant to a foreign exchange agreement between Venezuela’s Ministry of Finance and the BCV. See notes 2, 3 and 22(b) to our consolidated financial statements, included under “Item 18. Financial Statements.”

	Year ended December 31,
	Period End	Average (1)	High	Low
1999	647.53	609.29
2000	698.23	679.80
2001	770.09	722.01
2002	1,403.00	1,163.91
2003	1,600.00	1,611.32
2004(2)	1,920.00	1,893.00
February, 2005			1,920.00	1,915.20
March 2005—August, 2005(3)			2,150.00	2,144.60

(1) Represents the average exchange rate for each full month during the year, calculated based on the average daily exchange rate established by the BCV pursuant to the foreign exchange agreement referred to above.

(2) The exchange rate for the sale and purchase of the bolivar relative to the dollar was fixed by the Venezuelan government pursuant to a new foreign exchange regime of Bs. 1,920.00 to $1 and Bs. 1,915.20 to $1, respectively, commencing February 7, 2004.

(3) The exchange rate for the sale and purchase of the bolivar relative to the dollar was fixed by the Venezuelan government pursuant to a new foreign exchange regime at Bs. 2,150.00 to $1 and Bs. 2,144.60 to $1, respectively, commencing March 2, 2005.

On February 13, 2002, the Venezuelan government and the BCV adopted a floating exchange rate system in place of the band system. On January 21, 2003, the Venezuelan government and the BCV adopted temporary measures to restrict the convertibility of the Bolivar, and on February 5, 2003, the Venezuelan government

established a foreign exchange regime, setting the exchange rates for the sale and purchase of foreign currency at Bs. 1,600.00 to $1 and Bs. 1,596.00 to $1, respectively. It also created the Commission for the Administration of Foreign Exchange (CADIVI) and established rules for the administration and control of foreign currency. On February 7, 2004 a new foreign exchange rate for the sale and purchase of foreign currency was established at Bs. 1,920.00 to $1 and Bs. 1,915.20 to $1, respectively. On March 2, 2005 a new foreign exchange rate for the sale and purchase of foreign currency was established at Bs. 2,150.00 to $1 and Bs. 2,144.60 to $1, respectively.

Notwithstanding the new regime, the foreign exchange agreement between Venezuela’s Ministry of Finance and the BCV contains provisions that are specific to PDVSA, which have been in effect since 1982. Among other things, the foreign exchange agreement effectively exempts PDVSA and its affiliates from the exchange controls described above, up to a specified dollar limit. As a result, we believe that the exchange controls will not have a significant impact on PDVSA’s operations.

3.D Risk factors

Our business depends substantially on international prices for oil and oil products and such prices are volatile. A decrease in such prices could materially and adversely affect our business.

PDVSA’s business, financial condition, results of operations and prospects depend largely on international prices for crude oil and refined petroleum products. Prices of oil and refined petroleum products are cyclical and highly volatile, and have, historically, fluctuated widely due to various factors that are beyond our control, including:

• changes in global supply and demand for crude oil and refined petroleum products;

• political events in major oil producing and consuming nations;

• agreements among OPEC members;

• the availability and price of competing products;

• actions of commodity markets participants and competitors;

• international economic trends;

• technological advancements and developments in the industry;

• currency exchange fluctuations; and

• inflation.

Historically, OPEC members have entered into agreements to reduce their production of crude oil. Such agreements have sometimes increased global crude oil prices by decreasing the global supply of crude oil. Venezuela is a party to and has complied with such production agreement quotas, and we expect that Venezuela will continue to comply with such agreements in the future. Since 1998, OPEC’s production quotas have contributed to substantial increases in international crude oil prices.

Any reduction in our crude oil production or export activities that could occur as a result of changes in OPEC’s production quotoas or a decline in the prices of crude oil and refined petroleum products for a substantial period of time may materially and adversely affect our results of operations, cash flows and financial results.

Risks related to the ownership, regulation and supervision of PDVSA.

The Bolivarian Republic of Venezuela is the sole owner of Petróleos de Venezuela. The Venezuelan government, through the Ministry of Energy and Petroleum, establishes national petroleum policies and also

regulates and supervises PDVSA’s operations. The President of Venezuela appoints the president of Petróleos de Venezuela and the members of its board of directors by executive decree. Since November 2004, the Minister of Energy and Petroleum has also served as our President. However, the Bolivarian Republic of Venezuela is not legally liable for the obligations of Petróleos de Venezuela, including our guarantees of indebtedness of our subsidiaries, or the obligations of our subsidiaries.

Petróleos de Venezuela has been operated as an independent commercial entity since our formation; however, recent changes to the Venezuelan law regarding the oil sector impose significant social commitments upon PDVSA, which will affect our saving capacity, and, indirectly, our commercial affairs. Given that PDVSA is controlled by the Venezuelan government, we cannot assure you that the Venezuelan government will not in the future impose further material commitments upon PDVSA or intervene in our commercial affairs in a manner that will adversely affect our business. For instance, through Petróleos de Venezuela, the government could cause PDVSA Petróleo to reduce production or limit future capital expenditure to levels that would limit PDVSA Petróleo’s ability to generate the necessary flow of receivables to support payments on our indebtedness. In addition, despite recent precautions taken by the Company, we cannot assure you that opponents of the Venezuelan government will not seek to disrupt our activities through actions such as the work stoppages that occurred in late 2002 and early 2003, which in PDVSA’s opinion constituted sabotage.

We do not own any of the hydrocarbon reserves that we develop and operate.

Under Venezuelan law, the hydrocarbon reserves that we develop and operate belong to Venezuela. The exploration of these hydrocarbon reserves are reserved to Venezuela. PDVSA was formed to coordinate, monitor and control operations related to Venezuela’s hydrocarbon reserves.

While Venezuelan law requires that Venezuela retain exclusive ownership of PDVSA, it does not require the country to continue to conduct its crude oil exploration and exploitation activities through us. If the government elects to conduct its hydrocarbon activities other than through us, our operations will be materially and adversely affected. We can offer no assurance that changes in Venezuelan law or the implementation of policies by the Venezuelan government will not adversely affect our operations. See also “Item 7.A Major Shareholders and Related Party Transactions.”

Our business requires substantial capital expenditures.

The exploration and development of hydrocarbon reserves, production, processing and refining and the maintenance of machinery and equipment require substantial capital investments. We must continue to invest capital to maintain or to increase the number of hydrocarbon reserves that we operate and the amount of crude oil that we produce and process. We cannot assure you that we will maintain our production levels or generate sufficient cash flows or that we will have access to sufficient investments, loans or other financing alternatives to continue our refining, exploration and development activities at or above our present levels.

We are subject to production, equipment, transportation and other risks that are common to oil and gas companies.

As an integrated oil and gas company, we are exposed to production, equipment and transportation risks that are common to oil and gas companies, including fluctuations in production volume due to changes in reserve levels, production accidents, mechanical difficulties, adverse natural conditions, unforeseen production costs, condition of pipelines and the vulnerability of other modes of transportation and the adequacy of our equipment and production facilities. See “Item 4.B Business overview – Operations.”

These risks may lower our production levels, increase our production costs and expenses, or cause damage to our property or personal injury to our employees or others. We maintain insurance to cover certain losses and exposure to liability. However, consistent with industry practice, we are not fully insured against the risks described above. These risks may materially and adversely affect our operations and financial results. We cannot assure you that our insurance coverage is sufficient to cover all of our losses or our exposure to liability that may result from these risks.

Item 4. Information on the Company

4.A History and development of the company

PDVSA is the national oil and gas company of Venezuela. PDVSA was formed by the Venezuelan government in 1975 pursuant to the Organic Law Reserving to the State, the Industry and Commerce of Hydrocarbons (the “Nationalization Law”), and its operations are supervised by Venezuela’s Ministry of Energy and Petroleum (formerly the Ministry of Energy and Mines). Through its subsidiaries, PDVSA supervises, controls and develops the petroleum, petrochemical, gas, coal and Orimulsion® industries in Venezuela. These activities are complemented by PDVSA’s operating companies established abroad, which are responsible for refining and marketing activities in North America, Europe and the Caribbean. See also “Item 7.A Major Shareholders and Related Party Transactions.”

PDVSA’s oil-related activities are governed by the Organic Hydrocarbons Law, which came into effect in January 2002. PDVSA’s gas-related activities are regulated by the Organic Law of Gas Hydrocarbons of September 1999 and its Regulations dated June 2000.

Since its formation, PDVSA has been operated as a commercial entity, vested with commercial and financial autonomy. PDVSA and its domestic subsidiaries are organized under the Commercial Code of Venezuela, which sets forth the basic corporate legal framework applicable to all Venezuelan companies.

Furthermore, the National Constitution of the Bolivarian Republic of Venezuela and the Organic Hydrocarbons Law mandates that PDVSA contribute to social programs developed and administered by the Venezuelan government. For example, PDVSA and its subsidiaries Palmeven and CVP contribute management as well as financial resources in support of social programs related to education, healthcare, job creation, and subsidized food distribution.

PDVSA is domiciled in Venezuela and its registered office is located at Avenida Libertador, La Campiña, Apdo. 169, Caracas 1010-A, Venezuela, and our telephone number is 011-58-212-708-4111. Our website is: www.pdvsa.com. Information contained on our website is not incorporated by reference into this annual report.

4.B Business overview

PDVSA is engaged in various aspects of the petroleum industry, including:

•		the exploration, production and upgrading of crude oil and natural gas or upstream operations;

•		the exploration, production of natural gas from offshore sources, including the possibility for LNG export;

•		the refining, marketing and transportation of crude oil and refined petroleum products and the processing, marketing and transporation of natural gas, or downstream operations;

•		the production and marketing of petrochemicals. For our main petrochemical business unit “Pequiven,” the Venezuelan government decided in June 2005 to transfer the activities, assets and shares held by PDVSA in Pequiven (the company’s shareholder) to the Ministry of Energy and Petroleum and to submit this transfer for approval by the Shareholder of PDVSA. The transfer is subject to the reform of the Petrochemical Act and the resolution of other legal and administrative issues;

•		the development and marketing of Orimulsion®, Venezuela’s derivative of heavy and extra-heavy crude, which will be produced until expiration of the current supply agreement.

Our crude oil and natural gas reserves and our upstream operations are located in Venezuela, while our downstream operations are also located in Venezuela as well as the Caribbean, North America, and Europe.

PDVSA has been structured in three vertically integrated geographic divisions to manage its upstream operations, including: exploration, production, and upgrading. These divisions are: Eastern, Southern and the Western Division. Since August 2003, CVP, a subsidiary, assumed from PDVSA Petróleo the management of the third party contracts (operating and profit sharing agreements), the Orinoco Belt joint ventures and ultimately offshore natural gas licenses.

Our downstream operations include:

• operation of refineries, marketing of crude oil and refined petroleum products in Venezuela under the PDV brand name and under the CITGO brand name for the eastern and midwestern regions of the United States;

• conduct of most of our business in the Caribbean through the Isla Refinery (a refinery and storage terminal which we lease in Curaçao);

• operation of the storage terminals in Bonaire and the Bahamas in the Caribbean;

• ownership of equity interests in three refineries (one 50%-owned by ExxonMobil, one 58.75%-owned by Lyondell and one 50%-owned by Amerada Hess) and in a coker/vacuum crude distillation unit (50%-owned by ConocoPhillips) through joint ventures in the United States;

• ownership of equity interests in eight refineries and market petroleum products in Germany, United Kingdom, Belgium and Sweden through two joint ventures (one 50%-owned by BP RP and one 50%-owned by Neste Oil, which currently owns Fortum Oil and Gas);

• processing, marketing and transport of all natural gas in Venezuela; and

• conduct of shipping activities.

In the United States, we conduct our crude oil refining operations and refined petroleum product marketing through our wholly owned subsidiary, PDV Holding, which owns through PDV America, 100% of CITGO. CITGO also owns 41.25% of Lyondell-Citgo Refining LP. CITGO refines, markets and transports gasoline, diesel fuel, jet fuel, petrochemicals, lubricants, asphalt and other refined petroleum products in the United States. CITGO’s transportation fuel customers include primarily CITGO branded independent wholesale marketers, major convenience store chains and airlines located mainly along the east of the Rocky Mountains. Asphalt is generally marketed to independent paving contractors on the East Gulf and the Midwest Coasts of the United States. Lubricants are sold primarily in the United States to independent marketers, mass marketers and industrial customers. During 2003 CITGO sold lubricants, gasoline, and distillates in various Latin American markets, including Puerto Rico, Brazil, Ecuador, Chile, Argentina, Dominican Republic, Mexico, Panama and Guatemala, however, these activities were recently transferred to another PDVSA affiliate. Petrochemical feedstocks and industrial products are sold to various manufacturers and industrial companies across the United States. Petroleum coke is sold essentially in international markets. In 2004, CITGO sold a total of 26,811 millions gallons of petroleum products compared to 27,704 millions in the year 2003.

PDV Holding owns 50% of Chalmette Refining LLC (through PDV Chalmette) and 50% of Merey Sweeny L.P. (through PDV Sweeny). These joint ventures with Exxon Mobil and ConocoPhillips, respectively, process crude oil in the United States. PDVSA also owns 50% of Hovensa, a joint venture with Amerada Hess that processes crude oil in the U.S. Virgin Islands. We are, through our U.S. subsidiaries, one of the largest refiners of crude oil in the United States, based on our aggregate net ownership interest in crude oil refining capacity at December 2004, equivalent to 1,205 MBPD.

Within Europe, we conduct our crude oil refining and refined petroleum product activities through PDV Europa, which owns our 50% interest in Ruhr, a company based in Germany and jointly owned with BP. PDVSA also owns a 50% interest in Nynäs, a company with operations in Belgium, Sweden and the United Kingdom and jointly owned with Neste Oil, which currently owns Fortum Oil and Gas. Through Ruhr, we refine crude oil and

market and transport gasoline, diesel fuel, heating oil, petrochemicals, lubricants, asphalt and other refined petroleum products. Through Nynäs, we refine crude oil and market and transport asphalt, specialty products, lubricants and other refined petroleum products.

In Venezuela we have been conducting our petrochemical activities mainly through Pequiven, which has three petrochemical complexes in Venezuela and 17 joint ventures with private sector partners. However, as previously discussed, the Venezuelan Government decided in June 2005 to transfer Pequiven to the Ministry of Energy and Petroleum and Pequiven is currently evaluating the sale and transfer of its 17 joint ventures. Nevertheless, PDVSA will supply the feedstocks required by Pequiven. See also “Item 4.B Business overview – Marketing – Marketing in Venezuela – Petrochemicals.”

The gas business is conducted by the previously mentioned divisions (east and west exploration and production divisions), while the gas downstream operations and LNG segments are conducted by PDVSA Gas. CVP manages offshore gas natural projects.

Since 1997, Deltaven, a local retailing subsidiary, has marketed and distributed retail gasoline and other refined petroleum products in Venezuela, under the PDV brand. Deltaven also is promoting the development of the commercial infrastructure and services for retail clients together with the private sector.

Furthermore, PDVSA Finance was established in 1998 to serve as our principal vehicle for corporate financing through the issuance of unsecured debt.

Another important subsidiary is Intevep, through which we manage our research and development activities. PDVSA also has an educational center, CIED, which is responsible for the training and development of our personnel. CIED is currently under a restructuring process to better suit current PDVSA’s needs.

See “Item 4.C Organizational structure” for a list of our significant subsidiaries.

According to a comparative study published by Petroleum Intelligence Weekly on December 13, 2004, based on a combination of operating criteria and other data for 2003, such as: reserves, production, refining capacity and refined petroleum product sales, PDVSA is the world’s fourth largest vertically integrated oil and gas company, ranked fifth in the world in production, fifth in proved reserves of crude oil, fourth in refining capacity and eighth in product sales. Venezuela has been exporting crude oil, primarily to the United States, continously since 1914. At the end of 2003, we exported to the US market approximately 1,183 MBPD of crude oil and petroleum products and by December 2004, we were exporting to the US market approximately 1,367 MBPD of crude oil and petroleum products.

The oil sector has a great impact on the Venezuelan economy. In 2003, PDVSA accounted for approximately 18% of Venezuelan gross domestic product, 67% of its exports and 57% of government revenues. In 2004, PDVSA accounted for approximately 27% of Venezuelan gross domestic product, 83% of its exports and 48% of government revenues.

Business Strategy

Our business strategy is focused on the development of Venezuela’s hydrocarbon resources on behalf of the country with the support of both national and foreign private capital. This strategy aims to maximize the value of oil and gas resources and also to ensure our financial strength and stability, within the context of the dynamics of the energy market. Since oil is a nonrenewable resource with an expected imbalance between oil demand and supply for the mid-term, we continue to participate actively in the world oil market in order to receive a fair and stable oil price. Investments have to be made to avoid this expected imbalance, especially considering that it is predicted that an imbalance between the installed refining capacity and the market for refined products also exists.

This core strategy has been ratified in the 2005-2010 Corporate Business Plan.

PDVSA plans to intensively invest in both upstream and downstream projects in order to satisfy the current and expected increasing energy demand.

According to this plan for 2005-2010, operations in Venezuela will focus on:

• The exploration of condensate, light and medium crude oil. PDVSA financial resources will be mainly concentrated on the backyard areas. All other exploration regions either onshore or offshore are opened for third party participation, under the umbrella of the Venezuelan Organic Hydrocarbon Law, Gaseous Hydrocarbon Organic Law and, of course, the National Constitution.

• The production and marketing of the heavy and extra-heavy crude oil, including the huge reserves in the Orinoco Belt. According to the laws mentioned above, PDVSA is willing to develop new business opportunities with third parties in order to manufacture high quality products.

• The gas sector development. PDVSA is planning thefast track development of this business segment with third party participation in either onshore or offshore and under the framework of Venezuela’s Gaseous Hydrocarbon Law.

• In the downstream business we are looking for the right balance between our overseas and local assets in order to assure the domestic supply and quality for customers, in line with the strategy of maximizing the value of Venezuelan oil and gas resources.

• A new strategic objective consists of developing a sustainable social plan of large dimensions, aligned with the Social Plan of the Venezuelan Government. PDVSA’s social plan includes education, agricultural, infrastructure and local/regional development projects, which will generate about 1.7 million direct and indirect jobs and benefit 8.4 million people in Venezuela.

• We estimate that our business plan will require about $49 billion (excluding Pequiven) to achieve a sustainable production capacity of 5,109 MBPD by 2010. We expect to provide about 70% of the funds required for this Plan from our own resources and 30% by means of different financing sources. The following chart shows a summary of actual and estimated capital expenditures:

Capital Investment Plan 2005 – 2010 for Venezuela
($ in millions)

	Actual 2004	2005	2006	2007	2008	2009	2010	Total 2005- 2010
Exploration	134	314	443	459	426	413	247	2,302
Production (1)	1,438	2,381	2,658	2,783	2,326	2,174	2,100	14,422
Production Agreements	478	628	688	492	355	302	228	2,693
Orinoco Belt	64	809	647	587	338	450	336	3,167
Profit Sharing Agreement	46	340	291	177	348	352	183	1,691
Gas	443	973	2,248	2,213	1,753	1,168	581	8,936
Refining	177	328	576	3,217	3,476	3,475	3,061	14,133
Proesca (2)	89	12	27	66	67	248	721	1,141
Supply & trading	121	84	91	201	55	33	21	485
Total:	2,990	5,869	7,669	10,195	9,144	8,615	7,478	48,970

(1) 2005 includes $96 million for completion of the Orifuels Sinoven Joint Venture plant.

(2) The 2004 expenditure corresponds to Pequiven.

We also are committed to maintaining high safety and health standards across all operations and we aim to achieve effective and timely integration of business technologies in our operational activities to develop a sustainable competitive advantage. We also endeavor to provide quality training for our personnel; finally, the

business plan seeks to help to strengthen the national economy and to contribute to social programs such as education, healthcare and job creation.

We invested $2,990 million in operating assets in 2004. This expenditure was 42% lower than we had anticipated in our previous business plan. This was due to technical difficulties resulting from sabotage against the Venezuelan oil industry in December 2002 and the first quarter of 2003. Additionally, in 2004 PDVSA expensed $4,355 million as a contribution to social programs in Venezuela.

Furthermore, we will support the process of Latin America and Caribbean energy and economic integration promoted by the Venezuelan Government. We will also contribute effectively to put into practice the governmental initiative of building a new worldwide multipolar system of international relations based on justice, mutual respect and social equity. This initiative will allow Venezuelan people to achieve a better standard of living with less poverty and sustainable development.

These new social commitments have not, to date, materially or adversely impacted PDVSA Petróleos’s ability to generate the necessary flow of eligible receivables to support payments on our indebtedness.

As part of our business strategy, we intend to:

With respect to exploration, production and upgrading activities –

• incorporate reserves of light and medium gravity crude oil;

• increase our overall recovery factor;

• continue the development of our Orinoco Belt extra-heavy crude oil projects; and

• leverage existing technology in order to maximize the return on our investments.

With respect to refining and marketing –

• assure product enhancement and environmental compliance in Venezuela and abroad;

• expand and diversify our markets into Latin America, Caribbean and Asia, including China and India; and

• improve the efficiency of our refining processes and marketing activities.

With respect to natural gas –

• actively promote the national and international private sector participation in onshore and offshore non-associated gas reserves exploitation and processing;

• enhance our distribution processes in order to increase the breadth of our domestic and international markets; and

• assure participation in the liquified natural gas (LNG) markets.

With respect to petrochemicals –

• provide feedstocks and other raw material to Pequiven in a timely manner and continue to evaluate opportunities for petrochemical product development in our refineries abroad.

The execution of PDVSA’s Corporate Plan includes the following initiatives or business:

• Exploration, production and upgrading. The exploration and production strategy focuses on increasing our efforts to search for new light and medium gravity crude oil reserves and the systematic replacement of such reserves in back yard areas, developing new production areas, adjusting our production activities to cater market demands and agreements reached among OPEC members and other oil producing countries. For this purpose we will acquire 4,150 Km of 2D seismic lines, 20,593 Km² of 3D seismic lines and drill about 91 exploratory wells. PDVSA will drill some 3,751 production wells and perform maintenance (Ra/Rc) on 7,663 wells, among other activities, in order to reach a production capacity of 5,109 MBPD by 2010. PDVSA is also making efforts to maintain competitive production costs by using state-of-the-art technology. The first four Orinoco Belt projects have been completed and are in full operation: Hamaca (a PDVSA – ConocoPhillips & Chevron Texaco Joint Venture), Petrozuata (a joint venture between PDVSA and ConocoPhillips), Cerro Negro (a PDVSA – ExxonMobil – BP joint venture), Sincor (a PDVSA – TotalFina – Statoil joint venture). These strategic alliances are currently producing more than 600 MBPD of heavy and extra-heavy crudes. PDVSA will start a project to quantify and to certify proved hydrocarbons reserves in the Orinoco Belt, in order to determine the economic prospects and thus, properly direct future business in that area.

• Refining. Our refining strategy focuses on improving the efficiency of our downstream operations. In Venezuela, we will construct three new refineries: Cabruta (400 MBPD), Barinas (50 MBPD) and Caripito (50 MBPD). Also, we will add deep conversion capacity to the Puerto La Cruz, CRP (Amuay and Cardón) and El Palito refineries in order to increase the efficiency of heavy crude oil processing. In our refineries in the United States, Europe and the Caribbean we will invest in order to comply with quality standards demanded by those markets. Additionally, we will invest in the refineries of Kingston-Jamaica and Cienfuegos-Cuba, and develop a new refinery with Petrobras in the north of Brazil and in a deep conversion project in La Teja refinery in Uruguay. We continue to aim to achieve a higher margin on refined petroleum products and to comply with all applicable environmental quality standards. (See “Item 4.B. Business overview — Refining and Marketing”).

• Marketing. The plan considers continuing the expansion of our international marketing operations to ensure market share growth for our crude oil and refined petroleum products and to increase brand recognition for the products. Also, we seek to diversify our customer portfolio by entering new markets such as China and India. PDVSA will expand its operations in the Caribbean and South America through the Petroamerica initiative, which includes the Petrosur, Petrocaribe and Petroandina initiatives, in order to promote regional integration and a fair energy distribution among the Latin American nations. We aim to maintain our market position in the U.S. through a more efficient distribution system of CITGO and its refined petroleum products. CITGO International Latin America, Inc. “CILA”, which sells lubricants, gasoline and distillates in various Latin American countries, was recently transferred to Interven Venezuela and is currently evaluating the operation of its various subsidiaries. (See “Item 4.B. Business overview — Refining and Marketing”). Additionally, in order to improve our logistic and marine transportation capabilities, PDVSA will construct 42 tankers through strategic agreements with Argentina, Brazil, China and Spain, to increase from 21 to 58 the number of ships owned and operated by our subsidiary PDV Marina.

• In Venezuela, we plan to continue to promote a reliable supply of our products and the use of unleaded gasoline (a process started during the fourth quarter of 1999) to improve the competitive position of our network of service stations, lubrication centers and macro-stores, to continue the development of our commercial network through business relationships and other associations and to increase our product supply to high-traffic airports. Also, we are developing an ethanol production project in order to substitute octane enhancement additives such as TEL and MTBE in the production of gasoline. With the use of ethanol, we will have environmentally friendlier products and at the same time, we will be promoting agricultural and social development in rural areas, due to the fact that ethanol is produced from agricultural feedstocks such as sugarcane.

• Gas. The development of the gas business is one of our major goals. We plan to focus on creating attractive investment opportunities for the private sector in non-associated gas production, expanding

our transmission and distribution systems and natural gas liquids extraction, processing and fractioning capacity, and developing new gas export ventures, including exports of LNG. We intend to operate most of the existing associated natural gas production fields, currently assigned to us by the Ministry of Energy and Petroleum. We will continue to explore and develop non-associated gas reserves with the support of private investment. We expect to support the activities related to our gas business using our existing gas transmission and distribution systems.

• The Ministry of Energy and Mines, currently known as the Ministry of Energy and Petroleum, completed a round of onshore non-associated gas licensing bids for exploration and production activities in 11 new onshore areas in 2001. Six of those areas were awarded to foreign and domestic investors: Yucal-Placer Norte and Yucal-Placer Sur (both development areas), Barrancas, Tinaco, Tiznado and Barbacoas (each exploratory areas). The Yucal-Placer areas produced 44 MMCFD in 2004, and approximately 300 MMCFD are expected to be in production by 2010. During the first quarter of 2003, the Venezuelan Government assigned two blocks within the Deltana Platform area (eastern Venezuela and on the maritime border with Trinidad & Tobago) to Statoil and ChevronTexaco and ConocoPhillips. More recently it has assigned another block to ChevronTexaco. Additionally, we have under way a new bidding round to explore and develop offshore resources in the west and northeast of Venezuela; such developments will principally include projects for the production of LNG, once the local demand in Venezuela has been satisfied. We have defined an offshore natural gas project called Rafael Urdaneta located in the Venezuelan Gulf and northeast of Falcon State, with an area of 30,000 Km², split into 29 blocks to be offered in two phases. Phase one was initiated beginning the second quarter of 2005, when the Venezuelan Government offered the first six blocks to 37 national and foreign oil companies. Of this offer, blocks Urumaco I and II were awarded to the Russian company Gazprom, while block Cardon III was awarded to ChevronTexaco.

• We anticipate that development of our gas business segment will require approximately $9 billion in capital from 2005 to 2010. We expect that such capital expenditures will be obtained primarily from the private sector, including partners.

• We believe that our natural gas resources and Venezuela’s geographical location at the center of the Atlantic Basin puts us in an advantageous position to achieve our goals by 2010. We intend to capitalize on our advantages by promoting an increased and more diverse use of natural gas within the country.

• At this time, the Orimulsion® production is operated just to meet the needs of our clients in Europe, Asia and the United States. During 2003 we conducted a full review of this business. The outcome of such analysis showed that a reevaluation of our strategy was necessary within the framework of the new Corporate Strategy in order to maximize the value of Venezuelan natural resources. Since that reassessment, we produce only enough Orimulsion® to comply with our existing contracts. A new production module (Sinovensa) will be in place by the end of 2005 in order to supply the existing agreements.

Exploration and Production

Venezuela’s proved crude oil reserves have continued to increase over the years, with a cumulative production of crude oil from 1914 through December 31, 2003 totaling approximately 56.7 billion barrels. Venezuela’s commercial production of crude oil is concentrated in the Western Zulia Basin and the Western Barinas – Apure Basin in Western Venezuela and in the Monagas and Anzoategui states in the Eastern Basin. The large number of fields in production in these three basins are broadly distributed geographically and, as a result, substantially diversifies our production risk. The impact of a loss of production in any one field would be relatively minor when compared to Venezuela’s total production. The Western and Eastern basins have produced 41.0 billion and 15.7 billion barrels, respectively, of crude oil to date. Substantial portions of the sedimentary basins in Venezuela have not yet been explored.

Principal Oil-Producing Basins in Venezuela

The following table shows our proved reserves, proved and developed reserves, 2003 production and the ratio of proved reserves to annual production in each of the principal basins at December 31, 2003:

PDVSA’s Proved Reserves and Production by Basin

	Proved reserves(1)		Proved/ developed reserves	2003 Production		Ratio of proved
	(MMB at Dec. 31, 2003, except as otherwise indicated)		(MMB at Dec. 31, 2003, except as otherwise indicated)	(MBPD, except as otherwise indicated)		reserves/annual production (years)
Basin

Western Zulia:
Crude Oil	21,509		6,477	1,144	(2)	52
Natural Gas (BOE)	6,238		4,367	177	(3)	97
Western Barinas – Apure:
Crude Oil	1,842		927	86	(2)	59
Natural Gas (BOE)	40		28	1	(3)	110
Eastern:
Crude Oil (4)	53,789		8,884	1,616	(2)	91
Extra–Heavy Crude Oil included in previous quantity	35,186		3,010	455		212
Natural Gas (BOE)	19,591	(5)	13,714	414	(3)	130
Total Crude Oil (4)	77,140	(1)	16,288	2,846	(2)	74
Total Natural Gas (BOE)	25,869	(5)	18,109	592		120

(1) Developed and undeveloped.

(2) Includes condensate. Production obtained from the top of wells.

(3) Net natural gas production (gross production less natural gas reinjected).

(4) Includes proved reserves of heavy, extra-heavy crude oil and bitumen in the Orinoco Belt, estimated to be 35.2 billion barrels at December 31, 2003. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation.”

(5) Includes proved reserves of natural gas in the Orinoco Belt, estimated to be 2.45 billion BOE at December 31,2003.

The following table shows the location, 2003 production volume, discovery year, proved reserves and the ratio of proved reserves to annual production for each of PDVSA’s eleven largest oil fields as of December 31, 2003:

PDVSA’s Proved Reserves and Production by Field

Name of field	Location	2003 production	Year of discovery	Proved reserves	Ratio of proved reserves/annual production
	(State of)	(MBPD)		(MMB at Dec. 31, 2003)	(years)
Tía Juana	Zulia	201	1925	5,113	70
Lagunillas	Zulia	139	1925	2,464	49
Bachaquero	Zulia	141	1930	2,264	44
Bloque VII Ceuta	Zulia	104	1956	1,747	46
Urdaneta Oeste	Zulia	121	1955	1,501	34
Boscán	Zulia	99	1946	1,257	35
Mulata	Monagas	214	1941	2,106	27
El Furrial	Monagas	343	1986	1,999	16
Santa Barbara	Monagas	131	1941	1,570	33
Bare	Anzoátegui	40	1950	1,249	86
Jobo	Monagas	22	1956	1,077	134

Reserves

We use geological and engineering data to estimate our proved crude oil and natural gas reserves, including proved developed and undeveloped reserves. Such data is capable of demonstrating with reasonable certainty whether such reserves are recoverable in future years from known reservoirs under existing economic and operating conditions. We expect to recover proved crude oil and natural gas reserves principally from new wells and acreage that has not been drilled using currently available equipment and operating methods. Our estimates of reserves are not precise and are subject to revision. We review these crude oil and natural gas reserves annually to take into account, among other things, production levels, field reviews, the addition of new reserves from discoveries, year-end prices and economic and other factors. Proved reserve estimates may be materially different from the quantities of crude oil and natural gas that are ultimately recovered.

Crude oil and natural gas represented 75% and 25%, respectively, of our total estimated proved crude oil and natural gas reserves on an oil equivalent basis at December 31, 2003.

Crude Oil. We had estimated proved crude oil reserves at December 31, 2003 totaling approximately 77.1 billion barrels (including an estimated 35.2 billion barrels of heavy, extra-heavy crude oil and bitumen in the Orinoco Belt). We also had estimated proved reserves of natural gas totaling approximately 150,043 BCF (including an estimated 12,427 BCF in the Orinoco Belt). The average API gravity of our estimated proved crude oil reserves was 17.3° as compared to an average API gravity of 23° for our crude oil produced in 2002; the API gravity of the up-graded oil produced by the Orinoco Belt projects ranges from 16° to 32°. Based on 2003 production levels, estimated proved reserves of crude oil, including heavy and extra-heavy crude oil reserves that will require significant future development costs to produce and refine, have a remaining life of approximately 74 years.

From December 31, 1995 to December 31, 2003, our estimated proved reserves of crude oil increased by 10.8 billion barrels and our estimated proved reserves of natural gas increased by 1.12 billion barrels of oil equivalent (“BOE”). In 2003, 2002, 2001 and 2000, our proved crude oil reserve replacement ratio was 100%, 104%, 108% and 169%, respectively. These variations resulted from revisions to the expected recovery rate of oil in place and the application of secondary recovery technology to existing crude oil deposits.

Natural Gas. We have substantial proved developed reserves of natural gas amounting to 150,043 BCF (or 25,869 MMBOE) at December 31, 2003. Our natural gas reserves are comprised of associated gas that is developed incidental to the development of our crude oil reserves. A large proportion of our proved natural gas reserves are developed. During 2003, approximately 42% of the natural gas that we produced was reinjected for well pressure maintenance purposes.

The following table shows our proved crude oil and natural gas reserves and proved developed crude oil and natural gas reserves, all located in Venezuela (See note 23 to our consolidated financial statements, included under “Item 18. Financial Statements”):

PDVSA’s Proved Reserves

	Year Ended December 31,
	2003		2002		2001		2000		1999
Proved Reserves(1):
Crude oil (MMB)
Condensate	1,919		1,900		1,723		1,772		1,847
Light (API gravity of 30° or more)	10,078		10,012		10,345		10,244		10,258
Medium (API gravity of between 21° and 30°)	12,340		12,450		12,891		12,804		12,195
Heavy (API gravity of between 11° and 21°)	17,617		17,414		17,266		17,177		16,861
Extra-heavy (API gravity of less than 11°)(2)	35,186		35,381		35,558		35,688		35,701
Total crude oil	77,140		77,157		77,783		77,685		76,862
Of which, assigned to Operating Service Agreements(3)	5,446		5,501		5,600		5,479		5,450
Natural gas (BCF)(4)	150,043		147,109		148,295		147,585		146,611
Proved reserves of crude oil and natural gas (MMBOE)(3)(5)	103,009		102,521		103,351		103,131		102,140
Remaining reserves life of crude oil (years)(6)	74	x	70	x	64	x	64	x	70	x
Proved Developed Reserves:
Crude oil (MMB)
Condensate.	416		419		747		814		1,009
Light (API gravity of 30° or more)	2,760		2,716		3,590		3,803		3,827
Medium (API gravity of between 21° and 30°)	5,419		5,533		5,568		5,928		6,480
Heavy (API gravity of between 11° and 21°)	4,683		4,877		5,504		5,453		5,738
Extra-heavy (API gravity of less than 11°)(2)(7)	3,010		2,154		1,963		1,375		1,070
Total crude oil(7)	16,288		15,699		17,372		17,373		18,124
Of which, assigned to Operating Service Agreements(3)	1,267		1,935		1,523		1,413		1,329
Percentage of proved crude oil reserves(8)	21	%	20	%	22	%	22	%	24	%
Natural gas (BCF)	105,030		102,191		103,807		103,310		102,628
Percentage of proved natural gas reserves(9)	70	%	69	%	70	%	70	%	70	%
Proved developed reserves of crude oil and natural gas (MMBOE)(2)(3)	34,396		33,318		35,270		35,185		35,818

(1) Proved reserves include both proved developed and undeveloped reserves.

(2) Proved reserves of extra-heavy oil located in the Orinoco Belt have a low development grade. Of the total proved reserves to be exploited under the Orinoco Belt Project, at December 31, 2003, approximately 1,751 MMB were developed under four association agreements in which we have an equity interest of less than 50%.
See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects.”

(3) Portion of reserves in fields assigned to operating service agreements as of December 31 of the year in which each such operating agreement went into effect. Such agreements will not necessarily result in the exploitation of 100% of those reserves during their term. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

(4) Includes 12,427 BCF, 12,454 BCF, 12,476 BCF, 12,505 BCF and 12,400 BCF in each of 2003, 2002, 2001, 2000 and 1999, respectively, associated with extra-heavy crude oil reserves.

(5) Natural gas is converted to BOE at a ratio of 5.8 thousand cubic feet of natural gas per one barrel of crude oil.

(6) Based on crude oil production and total crude proved reserves. Proved reserves of extra-heavy crude oil in the Orinoco Belt are being developed in association with third parties. See note (2) above.

(7) Includes proved developed reserves of extra-heavy crude oil utilized in the production of Orimulsion®.

(8) Proved developed crude oil reserves divided by total proved crude oil reserves.

(9) Proved developed natural gas reserves divided by total proved natural gas reserves.

New Hydrocarbon Reserves Findings

In 2003, the Eastern PDVSA Division discovered new hydrocarbon reserves of approximately 159 million barrels of crude oil and 1,675 BCF of associated gas. Specifically in the North-East of Monagas State, near to Maturín well CHL-6X was discovered with 47 million barrels of crude oil and 350 BCF of associated gas. Currently, we are in the process of drilling the exploratory well CHL-7X, located near to well CHL-6X, with estimated hydrocarbon reserves of 255 million barrels of crude oil and 1,300 BCF of associated gas. In the North West of Monagas State, at the Tacata Field, the well TAC-2X with 118 million barrels of crude oil and 2,457 BCF

of associated gas was discovered. Further exploration activities include wells TAG-19 and TRAVI ESTE 1X in progress, with estimated reserves of 191 million barrels of crude oil and 629 BCF of associated gas.

In the Western part of the country, we continue our exploration activities at Franquera, Pauji and Misoa Formations of Eocene. Currently, we are drilling the Franquera 1-X exploratory well and we expect this reservoir to yield new reserves of 789 million barrels of crude oil and 378 BCF of associated gas.

Operations

We maintain an active exploration and development program designed to increase our proved crude oil reserves and production capacity. We have been successful in our efforts to increase our proved crude oil and natural gas reserves in each of the last 20 years. Beginning in 1992, we commenced a program designed to attract and incorporate private sector participation into our exploration and production activities. We currently conduct our exploration and development activities in the Western Zulia Basin, the Western Barinas – Apure Basin and the Eastern Basin in the Monagas and Anzoátegui states. We are currently conducting extensive exploration and development activities in the Orinoco Belt of the Eastern Basin and in the other basins, either independently or together with foreign partners through joint ventures. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation.”

In 2003, our exploration expenditures were used mainly to fund the drilling of 7 exploratory wells and the acquisition of 280 square kilometers of 3D seismic lines. No additional exploratory wells were drilled and no seismic lines were acquired pursuant to our operating service agreements. 250 MMB proved crude oil reserves were added in 2003 (162 MMB from newly discovered reserves and 88 MMB from development wells) compared to 238 MMB in 2002 (135 MMB from newly discovered reserves and 103 MMB from development wells), 357 MMB in 2001 (46 MMB from newly discovered reserves and 311 MMB from development wells) 209 MMB in 2000 (5 MMB from newly discovered reserves and 204 MMB from development wells) and 184 MMB in 1999 (84 MMB from newly discovered reserves and 100 MMB from developed wells) (These proved crude oil reserves do not include extensions of existing reserves, secondary extractions, or other factors. See note 23(a) to the financial statements, included under “Item 18. Financial Statements”). In 2003, we invested $526 million in 206 development wells and other facilities.

The following table summarizes our drilling activities for the periods indicated:

PDVSA’s Exploration and Development

	Year Ended December 31,
	2003	2002	2001	2000	1999
Exploration:
Wells spud	2	3	6	5	5
Wells carry-over	5	7	5	9	7
Total	7	10	11	14	12
Wells completed	3	3	3	2	0
Wells suspended	1	2	0	2	5
Wells under evaluation	0	0	3	5	1
Wells in progress	3	3	3	1	4
Dry or abandoned wells	0	2	2	4	2
Total	7	10	11	14	12
Development:
Development wells drilled (1)	206	366	479	474	349

(1) Includes wells in progress, even if they were wells spud in previous years, and injector wells. Does not include 26 development wells from PDVSA Gas and 62 development wells (including 2 injector wells) attributable to our operating service agreements located in the Eastern Division. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

Pursuant to the Orinoco Belt Extra-heavy Crude Oil Projects, no exploration wells and 64 development wells were drilled in 2003, 17 exploration wells and 144 development wells were drilled in 2002, 9 exploration wells and 349 development wells were drilled in 2001 and 15 exploration wells and 453 development wells were drilled in 2000.

In 2003, our crude oil production averaged 2,451 MBPD (including 122 MBPD attributable to our participation in the Orinoco Belt projects) with API gravity between 16° and 32°. This production level represented approximately 69% of PDVSA’s estimated 2003 year end crude oil production capacity of 3,529 MBPD (including 525 MBPD of crude oil production capacity attributable to our Orinoco Belt projects). During 2003, our average production costs of crude oil was approximately $3.85 per BOE, or $2.06 per BOE excluding the production and costs attributable to our operating service agreements, and the average of our depreciation and depletion costs was $0.53 per BOE. See “Item 3.A Selected financial data.”

At December 31, 2003, we operated approximately 15,782 oil wells. At such date, we had 37,659 gross kms² of undeveloped acreage and 177,829 gross kms² of acreage under development, including 49,194 kms² developed pursuant to our operating service agreements.

On average, during 2003, our natural gas production was 5,938 MMCFD (or 1,024 MBPD on an oil equivalent basis), of which 2,506 MMCFD, or 42%, was reinjected for purposes of maintaining reservoir pressure. The net natural gas production of 3,432 MMCFD was consumed in production of LNG (9%), as fuel in refinery and production operations (24%), in petrochemical operations (14%) and the remainder (53%) is sold to third parties for power generation, aluminum, iron and other manufacturing industries and domestic uses. Approximately 70% of the 2003 natural gas production and 76% of the total estimated proved net natural gas reserves are located in the Eastern Basin. A significant portion of this production is transported through our pipeline systems for use by industries in the coastal and central regions of Venezuela.

The following table summarizes our historical average net daily crude oil and natural gas production by type and by basin and the average sales price and production cost for the periods specified:

PDVSA’s Average Production, Sales Price and Production Cost

	Year Ended December 31,
	2003	2002	2001	2000	1999
	(MBPD, except as otherwise indicated)

Crude oil:
Condensate	22	46	48	50	43
Light (API gravity of 30° or greater)	727	774	1,135	1,174	1,189
Medium (API gravity of between 21° and 30°)	914	962	1,018	1,047	1,095
Heavy (API gravity of less than 21°)	788	877	893	814	623
Total crude oil	2,451	2,659	3,094	3,085	2,950
Of which, assigned to Operating Service Agreements(1)	465	481	502	466	404
Liquid petroleum gas	144	173	173	167	177
Total crude oil and liquid petroleum gas	2,595	2,832	3,267	3,252	3,127
Natural gas:
Gross production (MMCFD)	5,938	6,023	6,000	5,946	5,685
Less:
Reinjected (MMCFD)	2,506	2,351	1,907	1,967	1,919
Net natural gas (MMCFD)	3,432	3,672	4,093	3,979	3,766
Total crude oil, liquid petroleum gas and net natural gas (BOE)	3,187	3,464	3,973	3,938	3,776
Crude oil production by basin:
Western Zulia Basin	1,121	1,332	1,567	1,536	1,450
Western Barinas – Apure Basin	86	93	109	115	131
Eastern Basin	1,244	1,234	1,418	1,434	1,369
Total crude oil production	2,451	2,659	3,094	3,085	2,950

	Year Ended December 31,
	2003	2002		2001		2000		1999
	(MBPD, except as otherwise indicated)

Natural gas gross production by basin (MMCFD):
Western Zulia Basin	1,031	1,261		1,408		1,665		1,801
Western Barinas – Apure Basin	6	8		7		7		7
Eastern Basin	4,901	4,754		4,585		4,274		3,877
Total gross natural gas production	5,938	6,023		6,000		5,946		5,685
Average sales price(2):
Crude oil ($ per barrel)	24.39	$	21.35	$	18.95	$	24.94	$	15.35
Gas ($ per MCF)	0.61	$	0.71	$	0.88	$	0.90	$	0.73
Average production cost ($ per BOE)(3)	3.85	$	3.92	$	3.38	$	3.48	$	2.72
Average production cost ($ per BOE), excluding operating service agreements(3)	2.06	$	2.42	$	2.17	$	2.22	$	2.00

(1) See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Operating Service Agreements.”

(2) Including sales to subsidiaries and affiliates.

(3) The combined average production cost per barrel (for crude oil, natural gas and liquid petroleum gas), is calculated by dividing the sum of all direct and indirect production costs (including our own consumption but not including depreciation and depletion); by the combined total production volumes of crude oil, natural gas and liquid petroleum gas.

Initiatives Involving Private Sector Participation

As part of the process encouraging private initiatives and investment in the oil industry, and pursuant to Article 5 of the Nationalization Law, with the approval of the National Congress, we are permitted to enter into operating and association agreements with private entities. Since 1992, we have undertaken projects with the private sector in connection with our exploration and development activities.

In August 2003, to streamline our business operations and reduce our administrative costs, the administration of our business ventures with private sector entities was assigned to our subsidiary, CVP. In this regard, CVP assumed administrative responsibility within PDVSA with respect to our operating service agreements, strategic associations and profit sharing agreements described below. In addition to its administrative responsibilities, CVP will continue to promote PDVSA’s relations with third parties and private sector participation in the petroleum industry. However, any dividends and profits from production activities conducted pursuant to our operating service agreements and our other strategic associations continue to be paid to PDVSA, except for dividends from our profit sharing agreements, which are paid to CVP.

Operating Service Agreements

During 1992, 1993 and 1997, PDVSA auctioned the rights to and entered into agreements with several international companies. The purpose of these agreements was to reactivate the operation of thirty-three oil fields which no longer met our minimum rate of return on investment threshold, using secondary and tertiary recovery techniques. The auctions conducted during 1992 and 1993 are referred to in this annual report as the “first and second rounds” and the auction conducted in 1997 is referred to in this annual report as the “third round.”

The terms of the operating agreements entered into require the international oil company investors to make capital investments in the form of assets necessary to increase production in the relevant oil fields. These investors would then recover their investments by collecting operating fees and stipends from PDVSA, amounts to be determined based on pricing formulas derived from the amount of crude oil delivered to PDVSA during the term of the operating agreement. The operating agreements also provide that PDVSA would own the capital assets employed in the production, retain title to the hydrocarbons produced and have no further obligations as to any remaining value of the assets existing in the fields. See note 10(c) to our consolidated financial statements, included under “Item 18. Financial Statements.”

• The First and Second Rounds. A total of 27 oil companies (grouped in different consortiums) were awarded rights to drill 15 oil fields. Since then, some companies have changed their participation in the different consortiums. In 2003, Anadarko bought the participation of Union Pacific in the Oritupano-Leona field; ExxonMobil bought the participation of Ampolex in Quiamare-La Ceiba field and Repsol-YPF bought the participation of Union Pacific in the West Falcon field. An average of 313 MBPD of crude oil was produced from these fields in 2003, and it is expected that such production will be approximately 405 MBPD when the fields are in substantially full operation by 2005. As of December 31, 2003, these fields had estimated proved reserves of approximately 3.83 billion barrels of crude oil. Under this initiative, foreign companies have invested $5,535 million since 1992.

• The Third Round. We auctioned the right to reactivate, rehabilitate, develop and additionally explore certain hydrocarbon reservoirs in 18 fields, one of which is currently inactive. In 2003, ENI bought the participation of Lasmo in the Dación field. An average of 150 MBPD of crude oil was produced from these fields in 2003. As of December 31, 2003, these fields had estimated proved reserves of approximately 1.62 billion barrels of crude oil. Our business plan currently contemplates daily production from these fields of 225 MBPD by 2005 under our operating service agreements. Under this initiative, the operator companies have invested $3,548 million since 1997.

The following table sets forth information with respect to the contracts awarded to reactivate the fields under the operating service agreements:

PDVSA’s Operating Service Agreements
as of December 31, 2003

Area	Consortium (Operator)	Proved Crude Oil Reserves (MMB) (1)
First and Second Rounds
Boscán	Chevron Global Technology Services Co.	1,372.3
Urdaneta/West	Shell Venezuela S.A.	872.3
DZO	B.P. Venezuela Holdings, Ltd.	368.8
Oritupano/Leona	Petrobras Energía Venezuela, Servicios Corod de Venezuela, Anadarko	296.1
Colón	Tecpetrol Venezuela, CMS Oil and Gas, Coparex	157.2
Quiamare/LA Ceiba	Repsol–YPF Venezuela, S.A., Tecpetrol Venezuela, ExxonMobil	95.5
Quiriquire	Repsol–YPF Venezuela, S.A.	63.8
Pedernales	Perenco	116.2
Monagas Sur	Benton Oil & Gas, Vinccler	153.3
Sanvi/Güere	Teikoku Oil De Sanvi Güere, C.A.	81.9
Guárico East	Teikoku Oil De Venezuela C.A.	66.8
Jusepín	Total Oil and Gas de Venezuela, B.V., B.P. Venezuela Holding, Ltd.	132.4
Guárico West	Repsol–YPF Venezuela, S.A.	42.3
Falcón East	Vinccler	8.8
Falcón West	West Falcon Samson	2.7
Subtotal		3,830.4
Third Round
Boquerón	B.P. Venezuela Holding, Ltd., Preussag Energie GmbH	86.1
LL-652	Chevron Global Technology, Statoil, B.P. Venezuela Holding, Ltd., Petróleo y Gas Inversiones, C.A.	354.3
Dación	ENI	206.1
Intercampo norte	China National Petroleum Corp.	67.2
Caracoles	China National Petroleum Corp.	106.9
B2X 68/79	Nimir Petroleum Company Limited, Ehcopek Petróleo, S.A., Cartera de Inversiones Petroleras II, C.A.	107.4
Mene grande	Repsol–YPF Venezuela, S.A.	122.5
Mata	Inversora Mata, Petrobras Energía de Venezuela, S.A., Petrolera Mata	89.8
B2X 70/80	Pancanadian Petroleum Venezuela, S.A., Nimir Petroleum Company Limited	77.2
Kaki	Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.	37.8
Ambrosio	Perenco, Petróleo y Gas Inversiones, C.A.	52.5
Onado	Compañía General Combustibles, Carmanah Resources, Korea Petroleum, Bco Popular Del Ecuador	52.6
La Concepción	Petrobras Energía de Venezuela, S.A., Williams Companies, Inc.	119.6

Area	Consortium (Operator)	Proved Crude Oil Reserves (MMB) (1)
Cabimas	Preussag Energy GmbH, Suelopetrol	56.9
Casma Anaco	Cosa-Ingenieros Consultores, Cartera de Inversiones Venezolanas, Phoenix International, C.A., Rosewood North Sea, Open	11.4
Maulpa	Inemaka, Inversiones Polar, Petróleo y Gas Inversiones, C.A.	32.4
Acema	Coroil, Petrobras Energía de Venezuela, S.A.	35.1
Subtotal		1,615.8

Total		5,446.2

(1) These proved crude oil reserves correspond to the fields assigned to each of the operating service agreements and are included in our total proved crude oil reserves. Such operating service agreements will not necessarily result in the exploitation of 100% of those reserves during their term. See “Item 4.B Business overview—Exploration and Production—Reserves.” The proved reserves disclosed at December 31, 2003 do not include any additional reserves which may ultimately be proved based on recovery projects to be implemented by the operators of the service agreements.

During 2005, the Ministry of Energy and Petroleum has instructed PDVSA to convert the Operating Service Agreements to a scheme of jointly owned enterprises, where PDVSA will hold a minimum of 51% stock ownership, according to the Organic Hydrocarbons Law of Venezuela. CVP is analyzing each Operating Service Agreement and by the end of 2005, CVP is expecting to complete the conversion process.

Exploration and Production in New Areas under Profit Sharing Agreements

In July 1995, the Venezuelan Congress approved profit sharing arrangements pursuant to which private sector oil companies were offered the right to explore, drill and develop light and medium crude oil, on an equity basis in ten designated blocks with a total area of 13,774 square kilometers, pursuant to the terms of the profit sharing agreements entered into by such companies and CVP, our subsidiary appointed to coordinate, control and supervise these agreements. Under the profit sharing agreements, CVP has the right to participate, at its option, with an ownership interest of between 1% and 35% in the development of any recoverable reserves with commercial potential. Eight oil fields were awarded to 14 companies in 1996. The awards were based on the percentage of pretax earnings ranging up to 50% that the bidders were willing to share with the Venezuelan government. Our business plan currently contemplates an aggregate average daily production from the fields in these new areas of 460 MBPD by 2010. The profit sharing agreements provide for the creation of a Control Committee, as the ultimate authority for approval and control, and which shall make fundamental decisions of national interest for Venezuela in connection with the execution of these agreements.

In 2003, these companies invested approximately $55 million in activities related to the discovery, well evaluation, development and exploration efforts in Eastern Paria Gulf, La Ceiba and particularly in Western Paria Gulf, where the commercial stage of production has been reached. See note 10(b) to our consolidated financial statements, included under “Item 18. Financial Statements.”

CVP is entitled to hold shares representing a maximum of 35% participation in the joint ventures that could be formed pursuant to profit sharing agreements in the following oil fields:

Field	CVP Partners	Mixed companies
Western Paria Gulf	ConocoPhillips - ENI B.V. - OPIC (1)	Compañía Agua Plana, S.A.
Eastern Paria Gulf	Ineparia - ConocoPhillips - ENI B.V. - OPIC	Administradora del Golfo de Paria Este, S.A.
La Ceiba	ExxonMobil - PetroCanada	Administradora Petrolera La Ceiba, C.A.
San Carlos (2)	Petrobras Energía de Venezuela S.A.	Compañía Anónima Mixta San Carlos S.A.

(1) Profit sharing agreement under phase I (development).

(2) Changed to a gas license in 2002.

The profit sharing agreement with Punta Pescador was terminated in 2000, and agreements with Guanare, Guarapiche and Delta Centro were terminated in 2001. The San Carlos agreement was converted into a gas license in 2002.

A recent evaluation plan confirmed large hydrocarbon and gas reserves in the Western Paria Gulf field. It is anticipated that the field contains over two billion barrels of crude oil. On April 3, 2003, we approved phase I of the development plan for this field, involving a capital investment of approximately $557 million by investors and an expected production level of 250 million barrels of crude oil over the next 20 years. Phase I of this development will be conducted using a wellhead platform, a floating production unit with a separate accommodations platform, pipeline to a floating storage offtake vessel (FSO), and a mooring buoy for loading arriving tankers. Phase I also will include water injection for pressure maintenance. The produced associated gas will be stored in an aquifer zone wholly contained within the overall Corocoro gas column. The operator will manage the facilities design, construction installation and subsequent production operations. A total of 24 wells will be drilled comprising 11 producers, 10 water injectors, 2 gas injectors and one utility well. We estimate an average production of 55 MBPD in 2005, increasing to 120 MBPD in or after 2008.

It is currently projected that phase II (expected to commence in 2008) would involve a further $487 million of investments to recover additional reserves of up to 450 million barrels of crude oil from the field. We believe that we can make an efficient transition from phase I to phase II by using existing production facilities in the second phase. The total project cost for phase I and phase II is estimated at $4.3 per barrel, comprising $2.3 per barrel for development and $2.0 per barrel for operations.

In 2002 we invested $2.8 million for exploratory activities related to the Western Paria Gulf field. Additionally, in 2003 we drilled four development wells in that field, which required a total investment of $7.8 million. In the La Ceiba field we began drilling wells La Ceiba 3X and La Ceiba 6X and, depending on the evaluation of the results of those wells, a declaration of commercial operation will be issued to then begin the construction of production facilities to handle the early crude oil production, with an estimated investment of approximately $11 million.

Orinoco Belt Extra-Heavy Crude Oil Projects

The Venezuelan Congress approved the creation of four vertically integrated joint venture projects in the Orinoco Belt for the exploitation and upgrading of extra-heavy crude oil of average API gravity of 9° and marketing of the upgraded crude oil with API gravities ranging from 16° to 32°. These joint venture projects have been implemented through association agreements between the various participating entities and PDVSA. The term of each association agreement is approximately 35 years after commencement of commercial production, and, upon termination, the foreign participant’s ownership is transferred to PDVSA. Each of the projects is assigned an area that is expected to contain sufficient recoverable extra-heavy oil to meet planned output during the life of the association. For the foreign partners, the projects represent a significant opportunity to increase production and proved crude oil reserves. For us, the projects represent an opportunity to develop the Orinoco Belt’s extra-heavy crude oil reserves.

Each of these associations are required to pay the standard Venezuelan corporate tax rate of 34% (as compared to a tax rate of 50% that is applicable to our Venezuelan subsidiaries engaged in the production of hydrocarbons). In addition, they pay a production tax ranging between 1% to 16 2/3%, measured depending on accumulated revenues and total investment. These tax conditions were modified in October 2004. See note 23(a) to our consolidated financial statements, included under “Item 18. Financial Statements.” Also, these strategic associations benefit from a 10% investment tax credit on capital investments made after December 31, 2001, plus an additional 10% on capital investments that contribute to the environmental preservation of their operational areas.

The four joint venture projects in the Orinoco Belt are as follows:

• The Petrozuata Joint Venture. Petrozuata is a company owned by PDVSA Petróleo (a subsidiary of PDVSA) and ConocoPhillips. The construction of facilities at Petrozuata began in 1997. Initial production of extra-heavy crude oil commenced in August 1998. Upgraded facilities were completed

in 2001. During 2003, Petrozuata produced 104 MBPD of extra-heavy crude oil and 86 MBPD of upgraded crude oil with an average API gravity ranging from 16° to 24°. Under the terms of the joint venture agreement, ConocoPhillips has agreed to undertake the refining process at its Lake Charles refinery, in Lake Charles, Louisiana. By December 2003, total investments in this project amounted to $3,478 million.

• The Sincor Joint Venture. Sincrudos de Oriente is a joint venture owned by PDVSA Sincor (a subsidiary of PDVSA), TotalFina and Statoil. In 2003, this joint venture produced 158 MBPD of extra-heavy crude oil and 137 MBPD of upgraded crude oil with an average API gravity ranging from 24° to 32°. We anticipate that this joint venture will reach a production level of 180 MBPD of upgraded crude oil by 2007. By December 2003, total investments in this project amounted to $4,654 million.

• The Hamaca Joint Venture. Petrolera Hamaca is a company owned by Corpoguanipa (a subsidiary of PDVSA), ChevronTexaco and ConocoPhillips. Hamaca started producing upgraded crude oil in October 2004, achieving by the end of that year a production of 101 MBPD, with an average API gravity of 25° to 27°. In 2003, average production of extra-heavy crude oil was 67 MBPD and average production of diluted crude oil was 125 MBPD with an average gravity of 16° API. By December 2003, total investments in this project amounted to $2,544 million, of which, $472 million was invested in 2003.

• The Cerro Negro Joint Venture. Petrolera Cerro Negro is a company owned by PDVSA Cerro Negro, S.A. (a subsidiary of PDVSA), ExxonMobil and BP (formerly Veba Oel). Pursuant to the terms of this joint venture agreement, we have agreed to sell our share of upgraded crude oil produced by this joint venture (approximately 80% of total production) to Chalmette Refining, a refinery in Chalmette, Louisiana, which is an equal share joint venture between PDVSA and ExxonMobil. During 2003, this joint venture produced 101 MBPD of extra-heavy crude oil and 92 MBPD of upgraded crude oil with an average API gravity of 16°. By December 2003, total investments in this project amounted to $2,823 million. See “Item 4.B Business overview—Refining and Marketing—Refining” and note 10(a) to our consolidated financial statements, included under “Item 18. Financial Statements.”

The Orinoco Belt projects differ primarily by the quantity and quality of output. For the Hamaca and Sincor joint ventures, the projects are designed to produce upgraded crude oil that can be sold to third-party refiners who would otherwise process light sweet conventional crude oil. For the Petrozuata and Cerro Negro joint ventures, the projects are designed to produce upgraded crude oil that is suitable for a dedicated refinery.

The following table sets forth for each association in the Orinoco Belt, the parties estimated proved reserves in the areas associated with the projects and estimated production:

PDVSA’s Orinoco Belt Proved Reserves

Project	Private Sector Participants	PDVSA’s Interest	Gross Proved Reserves	Estimated Production of Upgraded Crude Oil		Expected Average API of Upgraded Crude Oil
		(%)	(MMB)	(MBPD)		(degrees)

Petrozuata	ConocoPhillips	49.90	2,567	120			16-19
Sincor	TotalFina, Statoil	38.00	3,497	210			30-32
Hamaca	ChevronTexaco, ConocoPhillips	30.00	1,046	190	(1)		25-27
Cerro Negro	ExxonMobil, BP (2)	41.67	3,373	120			16

(1) The upgrading facilities were not operating in 2003

(2) Formerly Veba Oel

Operating Service Agreement with National Universities

In October 2000, we entered into operating service agreements with three National Universities: Universidad de Oriente (Eastern University), Universidad del Zulia (Zulia University), and Universidad Central de Venezuela (Central University of Venezuela). In these agreements, we auctioned the right to reactivate, rehabilitate and develop fields located in three geographical areas. The purpose of these agreements with the National Universities is to provide training and industry experience to Venezuelan university students, especially geophysics, petroleum engineers and geology students.

Each field will be developed by separate entities that are 51% owned by us and 49% owned by the respective universities. These fields are: Socororo, located in Anzoátegui State, operated by Petroucv, S.A., with an assigned surface of 257 square Km; Mara Este, located in the Zulia State, operated by Oleoluz, S.A., with an assigned surface of 246 square Km; and Jobo, located in Monagas State, operated by Petroudo, S.A. with an assigned surface of 19.57 square Km. The total assigned area for all these fields is approximately 523 square kilometers. As of December 31, 2003, these fields have estimated proved reserves of approximately 234 MMB of crude oil (consisting of 50.5 MMB at Socororo, 69.3 MMB at Mara Este and 114.2 MMB at Jobo, respectively), with an average API gravity of 8° to 22° API. During 2003, the total oil production under these operating service agreements was 2.5 MBPD. We expect these fields to produce approximately 35 MBPD by 2007. We also anticipate investing a total of approximately $202 million in these fields over the next 20 years. By December 2004, total expenditures amounted to $25.8 million.

Overview of Main Projects with Private Sector Participation

The Plataforma Deltana Project

The Plataforma Deltana area is located 250 km offshore East of the Orinoco River Delta and Southeast of the territorial border with the Republic of Trinidad and Tobago (Trinidad and Tobago). For bidding and business purposes, the zone has been divided into five blocks mainly prospective for non-associated gas. The main objective of the project is to confirm and develop new non-associated natural gas reserves to meet domestic market requirements as well as for export, mainly to the Atlantic Basin.

The first exploration phase, with disbursement amounting to $180 million, was completed by PDVSA on July 9, 2003 in an area of 1,000 square kilometers next to the territorial border with Trinidad & Tobago. Such exploration activity resulted in an increase of the non-associated natural gas reserves estimates to 5.6 Trillion cubic feet as audited by the specialized firm Ryder Scott. A 10 TCF short term proven reserves objective is being considered as part of the second exploratory phase being executed in the period 2004-2005 by the companies working in the area under the granted licenses, to assure the commercial development of the Plataforma Deltana area. Total investment in this project has been estimated at approximately $4 billion.

Licenses for exploration and development for blocks 2 and 4 were granted by the Ministry of Energy and Petroleum to three international oil and gas companies in February 2003 (ChevronTexaco and ConocoPhillips in Block 2 and Statoil in Block 4). The international companies are committed to a minimum exploratory program, with an estimated investment of $150 million (drilling activities started in August 2004), and to subsequent investments for development if commercial viability is confirmed. PDVSA’s participation in the partnership, which could range from 1% to 35%, will be determined upon declaration of commercial viability.

The selection process of partners for block 3 was completed in 2003. In February 2004 the Ministry of Energy and Petroleum granted the license for exploration and development to ChevronTexaco. Block 1 is reserved for business opportunities, subject to an unitization agreement with Trinidad and Tobago. On August 2003 a memorandum of understanding was signed between the two countries to manage all common reservoirs along the territorial border. The exploratory program for this block will cost approximately $27 million. Block 5 remains for future growth opportunities.

The natural gas produced offshore will be processed onshore in a new industrial complex to be located near the city of Guiria, in Sucre State in the North East of Venezuela. It is planned that this industrial complex will also

serve the LNG Mariscal Sucre and other gas projects in the region. The application of international health, safety and environment standards and sustainable development practices are key strategies for the development of this area. This project will contribute to Venezuela’s natural gas business expansion, and will further diversify the country’s energy sources.

Mariscal Sucre Project

The main purpose of this project is the development of North Paria fields, at the North East of Venezuela to produce non-associated natural gas to supply both local and international markets. The project involves production of 1,070 million cubic feet of natural gas per day (MMCFD); the construction of a gas liquefaction train with a design capacity of 4.7 million metric tons per year (MMTY). As a reference, one of the development scenarios for the four Mariscal Sucre Project’s fields consist of a total of 45 reservoirs that are going to be drained with 36 wells and drilled in 4 development phases over a period of about 20 years.

The first drilling phase comprises 14 platform wells – average of 31 days to drill and 14 days to complete if no downhole chemical injection is needed – and will all be completed with the use of a deepwater cantilever jack-up rig. The initial wells will be at Río Caribe (6 wells) and Mejillones (8 wells) from four platforms. The Central Production Facility (CPF) for the entire development will be located at Mejillones and initially, it will gather all production. The export pipeline will initiate from this platform, and the offshore central control room will be located on this structure. There are no processing facilities on the CPF. The gas, condensate, and produced water will be routed to the LNG plant at Güiria by a multi-phase export pipeline. All platforms will contain power generation and associated utilities.

Estimated initial production will be 17,000 BPD of stabilized condensate from Rio Caribe and 1,070 MMCFD of gas from all fields. During this phase, the bulk of condensate will come from Rio Caribe.

The total estimated investment is $2,700 million. First stage activities include basic services, dock services, port services, general services, corridors services, roads and security, residential area and relocation of city airport.

Refining and Marketing

Refining

Our downstream strategy has been focused on the expansion and upgrading of our refining operations in Venezuela, the United States and Europe, allowing us to increase our production of refined petroleum products and upgrade our product slate toward higher-margin refined petroleum products. We have also increased the complexity of our refining capacity in Venezuela and made extensive investments to convert our worldwide refining assets from simple conversion to deep conversion capabilities. Deep conversion capabilities in our Venezuelan refineries have enabled us to improve yields by allowing a greater percentage of higher value products to be produced. Such capabilities have resulted in an increase in our gasoline and distillate yield from 35% in 1976 to 70% in 2003, and has allowed us to reduce our fuel oil production from 60% to 23% during the same period, resulting in an improved export product portfolio.

We conduct refining activities in Venezuela, the Caribbean, the United States and Europe. Our net interest in refining capacity has grown from 2,362 MBPD in 1991 to 3,092 MBPD at December 31, 2003. The following diagram presents a summary of PDVSA’s refining operations in 2003:

PDVSA’s Refining System

PDVSA’s Refining Capacity

The following table sets forth the refineries in which we hold an interest, the rated crude oil refining capacity and our net interest at December 31, 2003:

	Owner	PDVSA Interest	Total Rated Crude Oil Refining Capacity	PDVSA Net Interest in Refining Capacity
		(%)	(MBPD)	(MBPD)

Venezuela
Paraguaná Refining Complex, Falcón	PDVSA	100	940	940
Puerto La Cruz, Anzoátegui	PDVSA	100	203	203
El Palito, Carabobo	PDVSA	100	130	130
Bajo Grande, Zulia	PDVSA	100	15	15
San Roque, Anzoátegui	PDVSA	100	5	5
Total Venezuela			1,293	1,293
Netherlands Antilles (Curaçao)
Isla (1)	PDVSA	100	335	335
United States
Lake Charles, Louisiana	CITGO	100	320	320
Corpus Christi, Texas	CITGO	100	157	157
Paulsboro, New Jersey	CITGO	100	84	84
Savannah, Georgia	CITGO	100	28	28
Houston, Texas(2)	LYONDELL-CITGO	41	265	109
Lemont, Illinois	CITGO	100	167	167
Chalmette, Louisiana(3)	Chalmette Refining	50	184	92
Saint Croix, U.S. Virgin Islands(4)	Hovensa	50	495	248
Total United States			1,700	1,205
Europe
Gelsenkirchen, Germany(5)	Ruhr	50	230	115
Schwedt, Germany(5)	Ruhr	19	240	45
Neustadt, Germany(5)	Ruhr	13	260	33
Karlsruhe, Germany(5)	Ruhr	12	312	37
Nynäshamn, Sweden(6)	Nynäs	50	29	15
Gothenburg, Sweden(6)	Nynäs	50	11	5
Dundee, Scotland(6)	Nynäs	50	9	4
Eastham, England(6)	Nynäs	25	18	5
Total Europe(7)			1,109	259
Total outside Venezuela			3,144	1,799
Worldwide Total			4,437	3,092

(1) Leased in 1994. The lease expires in 2019.

(2) A joint venture with Lyondell Chemical Company.

(3) A joint venture with ExxonMobil

(4) A joint venture with Amerada Hess.

(5) A joint venture with BP RP.

(6) A joint venture with Neste Oil, which currently owns Fortum Oil and Gas.

(7) Antwerp, Belgium was divested in 2003

In order to maintain our competitiveness within international markets, we expect to invest approximately $14,133 million from 2005 through 2010 in Venezuela to improve our refining systems and to adapt our systems to meet environmental regulations and domestic and international product quality requirements. The refining plan includes projects aimed at manufacturing gasoline. On March 13, 2001, we entered into a contract for approximately $300 million with a Venezuelan-Japanese Consortium led by the Japanese JGC Corporation (formed by the Japanese Chiyoda Corporation and the Venezuelan companies, Jantesa and Vepica) to construct naphtha hydrotreating facilities and diesel hydro-desulphurization and environmental units in a refinery located in Puerto La Cruz, referred to in this annual report as the VALCOR project. The primary objective of this project was to produce unleaded gasoline to meet the demands of the local market and to produce distillates of low sulphur content for export to international markets.

The facilities and processing units were completed in December 2004 at a cost of $545 million. VALCOR is currently in production mode, producing 45 MBPD of gasoline and 30 MBPD of diesel blending components.

Additionally, the two fluid catalytic cracking units located at our Amuay and Cardón refineries (Paraguaná Refining Complex - PRC), are being modified to manufacture more gasoline. A low sulfur gasoline production unit (currently in the engineering phase) based on our own technology (ISAL® developed by Intevep, a wholly-owned subsidiary of PDVSA) is expected to be operational in the Amuay refinery by 2006 and another similar unit will be installed at the Isla refinery in Curacao sometime in the refining plan period. We also plan to increase the heavy crude refining capacity, and we foresee the expansion of our delayed coking plants located at the refining complex in Paraguaná, Venezuela, and we are also performing studies to increase Venezuela’s refining capacity.

Venezuela and the Caribbean

Our refineries in Venezuela are located at Amuay-Cardón (PRC), Puerto La Cruz, El Palito, Bajo Grande and San Roque, with rated crude oil refining capacities of 635- 305 MBPD, 203 MBPD, 130 MBPD, 15 MBPD and 5 MBPD, respectively. We also operate the Isla Refinery in Curaçao, which we lease on a long-term basis from the Netherlands-Antilles government. The lease expires in 2019. Through these refineries, we produce reformulated gasoline and distillates to meet the U.S. and other international market requirements.

United States

Through our wholly owned subsidiary, CITGO, we produce light fuels and petrochemicals primarily through our refineries in Lake Charles, Louisiana; Corpus Christi, Texas; and Lemont, Illinois. Our asphalt refining operations are carried out through refineries in Paulsboro, New Jersey; and Savannah, Georgia.

CITGO’s largest supplier of crude oil is PDVSA. CITGO has entered into long-term crude oil supply agreements with PDVSA with respect to the crude oil requirements for each of CITGO’s Lake Charles, Corpus Christi, Paulsboro and Savannah refineries. These crude oil supply agreements require PDVSA to supply minimum quantities of crude oil and other feedstocks to CITGO, usually from 20 to 25 years. These crude supply agreements contain force majeure provisions that entitle the supplier to reduce the quantity of crude oil and feedstocks delivered under the crude supply agreements under specified circumstances.

The Lake Charles refinery has a rated refining capacity of 320 MBPD and is capable of processing large volumes of heavy crude oil into a flexible slate of refined products, including significant quantities of high-octane unleaded gasoline and reformulated gasoline. A project to increase the crude oil distillation capacity by 105 MBPD was completed and became operative by February 2005, so this refinery is currently the fourth largest in the U.S. with a total refining capacity of 425 MBPD. The Lake Charles refinery’s main petrochemical products are propylene, benzene and mixed xylenes. Its industrial products include sulphur, residual fuels and petroleum coke. This refinery has one of the highest capacity levels for higher value-added products production in the United States, with a multiple stream capacity that allows it to continue operating with one or more units shut down. This refinery has a Solomon Process Complexity Rating of 18.2 (as compared to an average of 14.0 for U.S. refineries in Solomon Associates, Inc.’s most recently available survey). The Solomon Process Complexity Rating is an industry measure of a refinery’s ability to produce higher value products. A higher Solomon Process Complexity Rating indicates a greater capability to produce such products.

The Corpus Christi refinery has a refining capacity of 157 MBPD and a processing technology that enables it to produce premium grades of gasoline that exceed that of most of its U.S. competitors and to reduce sulfur levels in refined petroleum products. This refinery has a Solomon Process Complexity Rating of 16.5. The Corpus Christi refinery’s main petrochemical products include cumene, cyclohexane, and aromatics (including benzene, toluene and xylenes).

The Lemont refinery processes heavy crude oil into a flexible slate of refined products. The refinery has a rated refining capacity of 167 MBPD and has a Solomon Process Complexity Rating of 11.7. This refinery is one of the most recently designed and constructed refineries in the United States. It is a flexible deep conversion facility that produces primarily gasoline, diesel, jet fuel and petrochemicals.

The refineries in Paulsboro, New Jersey and Savannah, Georgia are specialized asphalt refineries. The Paulsboro refinery, which is particularly suited to processing asphalt, also has facilities to process low sulfur, light crude oil whenever favorable conditions exist.

Through LYONDELL-CITGO, a joint venture owned 41.25% by PDVSA and 58.75% by Lyondell, we have a net interest in refining capacity of 109 MBPD in a refinery located in Houston, Texas with a refining capacity of 265 MBPD. PDVSA supplies a substantial amount of the crude oil processed by this refinery under a long-term crude oil supply agreement that expires in the year 2017. Under this agreement, LYONDELL-CITGO purchased approximately $1.7 billion of crude oil and feedstocks at market related prices from PDVSA in 2003. CITGO purchases substantially all of the gasoline, diesel and jet fuel produced at this refinery under a long-term contract.

Various disputes exist between LYONDELL-CITGO and its partners and their respective affiliates concerning the interpretation of agreements between the parties relating to the operation of the refinery.

PDVSA Petróleo, pursuant to its contractual rights under the crude oil supply agreement with LYONDELL-CITGO, declared a force majeure situation in April 1998, and again in February 1999 through October 2000, as well as from February 2001 to March 2003. PDVSA, pursuant to its contractual rights under the supplemental supply agreement with LYONDELL-CITGO, which guarantees PDVSA Petróleo’s obligations under the crude oil supply agreement, invoked its right to declare a force majeure situation during the same time periods. As a result of these declarations PDVSA Petróleo and PDVSA were relieved of their obligations to deliver crude oil under both agreements and LYONDELL-CITGO purchased crude oil from alternate sources. LYONDELL-CITGO received notice of force majeure from PDVSA Petróleo and/or PDVSA in December 2002. LYONDELL-CITGO purchased crude oil in the spot market to replace the volume not delivered under contract. The force majeure was lifted on March 6, 2003. In February 2002, LYONDELL-CITGO commenced an action against PDVSA and PDVSA Petróleo, in the United States District Court for the Southern District of New York seeking damages for

alleged breaches of the long-term crude oil supply agreement between LYONDELL-CITGO and Lagoven (subsequently merged into PDVSA Petróleo) and the supplemental supply agreement, between LYONDELL-CITGO and PDVSA. Both agreements are dated May 5, 1993 and expire in 2017. On May 31, 2002, PDVSA and PDVSA Petróleo filed a motion to dismiss the case. On August 6, 2003, the judge dismissed one of the ten counts in the complaint, allowing the remaining counts to proceed through early stages of litigation. The parties engaged in extensive discovery beginning in November 2003. In the course of expert discovery, on September 30, 2004, one of LYONDELL-CITGO’s retained experts filed a report listing the amount of liquidated damages owed by PDVSA and PDVSA Petróleo to LYONDELL-CITGO through September 2004 as $125,117,465. For the same period, LYONDELL-CITGO’s expert calculated the amount of actual damages as $258,447,787 to $259,743,967, depending on the method used to calculate interest. LYONDELL-CITGO also claims additional unspecified amounts for attorneys’ fees and costs. Discovery was formally concluded on October 1, 2004. On October 1 and October 6, 2004, the magistrate judge issued orders directing PDVSA and PDVSA Petróleo to produce all Board of Directors minutes and related documents to LYONDELL-CITGO. PDVSA informed the magistrate judge that it could not comply with his order because granting LYONDELL-CITGO unrestricted access to PDVSA’s Board of Directors materials violated Venezuelan law. The magistrate judge entered an adverse inference sanction against PDVSA and PDVSA Petróleo, ordering that the court may infer that the Board of Directors’ documents were unfavorable to PDVSA and favorable to LYONDELL-CITGO. The magistrate judge also ordered that the court may give the strongest weight to the evidence already in the case in favor of LYONDELL-CITGO, but may also consider any evidence presented by PDVSA to explain why it did not produce the Board of Directors materials. The judge affirmed the magistrate judge’s adverse inference instruction on April 29, 2005. Meanwhile, on October 22, 2004, both parties filed motions for summary judgment with the court, which have been fully briefed. These motions are still pending. Management of the companies intends to contest vigorously LYONDELL-CITGO’s claims. See “Item 8.A.7 Legal Proceedings.”

Through Chalmette Refining, an equal-share joint venture between PDVSA and ExxonMobil, we have a net interest in refining capacity of 92 MBPD in a refinery located in Chalmette, Louisiana. The Chalmette refinery processes upgraded extra-heavy crude oil to be produced by our Cerro Negro joint venture. PDVSA (through PDV Chalmette) has an option to purchase up to 50% of the refined products produced at the Chalmette refinery. PDVSA did not exercise or assign this option to CITGO for 2001 or 2002 or 2003. ExxonMobil, which operates both the Cerro Negro joint venture and the Chalmette refinery, purchased substantially all of the refined products produced by the Chalmette refinery at market prices during 2002 and 2003. See “Item 4.B Business overview—Initiatives Involving Private Sector Participation—Orinoco Belt Extra-Heavy Crude Oil Projects.”

PDV Holding and ConocoPhillips own an integrated 58 MBPD coker and 110 MBPD vacuum crude distillation unit within an existing refinery owned by ConocoPhillips in Sweeny, Texas. Each party owns a 50% equity interest in this facility. ConocoPhillips has entered into a long-term crude oil supply agreement with us to supply the Sweeny refinery with heavy sour crude oil. Revenues from the Sweeny joint venture will consist of fees paid by ConocoPhillips to the joint venture under the processing agreement and any revenues from the sale of coke to third parties. Effective December 6, 2002, PDVSA declared force majeure under the Crude Oil Supply Agreement and stopped shipment of heavy sour crude oil to the Conoco Sweeny refinery. During the period of force majeure, ConocoPhillips obtained heavy, sour crude oil from alternative sources. PDVSA lifted the force majeure on March 6, 2003, at which time ConocoPhillips resumed receipt of minimal crude volumes. By July 2003, the crude supply deliveries were back to normal.

We own a 50% interest in the Hovensa refinery in the U.S. Virgin Islands, previously owned by Hess Oil Virgin Islands Corporation, with a current refining capacity of approximately 495 MBPD. The joint venture has entered into long-term supply contracts with PDVSA for up to 60% of its crude oil requirements. During 2002, Hovensa completed construction of a delayed coker unit and related facilities that it had been building in connection with the formation of the joint venture.

Europe

Through Ruhr, a joint venture owned 50% by PDVSA and BP RP, we have equity interests in four German refineries (Gelsenkirchen, Neustadt, Karlsruhe and Schwedt) in which our net interest in crude oil refining capacity at December 31, 2003 was 115 MBPD, 33 MBPD, 37 MBPD and 45 MBPD, respectively. Ruhr also owns two petrochemical complexes (Gelsenkirchen and Münchmünster). The Gelsenkirchen complex, which includes

modern, large-scale units that are integrated with the crude oil refineries located in the same complex, primarily produces olefins, aromatic products, ammonia and methanol. The Münchmünster complex, integrated with the nearby Bayernoil refinery, primarily produces olefins. Ruhr’s petrochemical complexes have an average production capacity of approximately 3.8 million metric tons per year of olefins, aromatic products, methanol, ammonia and various other petrochemical products.

Through Nynäs, a joint venture owned 50.001% by PDV Europa and 49.999% by Neste Oil, we own interests in three specialized refineries: Nynäshamn and Gothenburg in Sweden and Dundee in Scotland. Our net interest in crude oil refining capacity in each of these refineries at December 31, 2003 was 15 MBPD, 5 MBPD and 4 MBPD, respectively. The Nynäs refineries are specially designed to process heavy sour crude oil. Nynäs also owns a 25% interest in a refinery in Eastham, England. The Eastham refinery is a specialized asphalt refinery in which our net interest crude oil refining capacity at December 31, 2003 was 5MBPD.

The Nynäs refineries in Nynäshamn produce asphalt and naphthenic specialty oils. The Dundee, Gothenberg and Eastham refineries are specialized asphalt refineries. Nynäs purchases crude oil from us and produces asphalt and naphthenic specialty oils, two products for which Venezuelan heavy sour crude oil is particularly well suited feedstock due to its proportions of naphthenic, paraffinic and aromatic compounds. Asphalt products are used for road construction and various industrial purposes, while naphthenic specialty oils are used principally in electrical transformers, as mechanical process oils and in the rubber and printing ink industries.

The following table sets forth our aggregate refinery capacity, input supplied by us (out of our own production or bought in the open market), product yield and utilization rate for the three-year period ended December 31, 2003.

PDVSA’s Refinery Production

	Year Ended December 31,
	2003			2002			2001
	MBPD		% of Total	MBPD		% of Total	MBPD		% of Total
Total refining capacity	4,437			4,368			4,368
PDVSA’s net interest in refining capacity	3,092			3,085			3,085
Refinery input(1):
Crude oil
PDVSA(2)	1,856		67	1,848		70	2,018		72
Light (API gravity of 30º or greater)	560		20	565		21	551		20
Medium (API gravity of between 21º and 30º)	821		30	850		32	983		35
Heavy (API gravity of less than 21º)	475		17	433		17	484		17

Other	533		19	440		16	483		17
Light (API gravity of 30º or greater)	308		11	330		12	356		13
Medium (API gravity of between 21º and 30º)	137		5	84		3	120		4
Heavy (API gravity of less than 21º)	88		3	26		1	7		0
Crude oil subtotal	2,389		86	2,288		86	2,501		89

Other feedstocks
PDVSA	242		9	250		9	168		6
Other	147		5	120		5	139		5
Other feedstocks subtotal	389		14	370		14	307		11

Total refinery input(3)
PDVSA	2,098		76	2,098		79	2,186		78
Other	680		24	560		21	622		22
Total	2,778		100	2,658		100	2,808		100

Product yield(4):
Gasoline/Naphtha	969		36	951		37	1,006		35
Distillate	874		32	817		31	947		33
Low sulfur residual	47		2	30		1	34		1
High sulfur residual	339		13	273		11	339		12
Asphalt/Coke	182		7	177		7	211		8
Naphthenic specialty oil	9		0	12		1	9		0
Petrochemicals	110		4	92		3	92		3
Other	170		6	225		9	225		8
Total product yield	2,700		100	2,577		100	2,863		100

Utilization(5)	77	%		74	%		81	%

(1) Our refineries sourced 78%, 81% and 81% of our total crude oil requirements from crude oil produced by us in 2003, 2002 and 2001, respectively.

(2) Sourced by us (including supplies from entities that are not subject to our control).

(3) Includes our interest in crude oil and other feedstocks.

(4) Our interest in product yield.

(5) Crude oil refinery input divided by the net interest in refining capacity.

In 2003, we supplied substantially all of the crude oil requirements to our Venezuelan refineries (approximately 857 MBPD), 177 MBPD of crude oil to our leased refinery in Curaçao and an aggregate of 1,355 MBPD of crude oil to refineries owned by our international subsidiaries or in which we otherwise have an interest. Of the total volumes supplied by us to our international affiliates, 210 MBPD were purchased by PDVSA in the global market and supplied to our European affiliates. Additionally, CITGO purchased a total of 336 MBPD of crude oil from PDVSA for processing in their refineries.

Marketing

In 2003, we exported 1,648 MBPD of crude oil or 67% of our total crude oil production and 502 MBPD of refined petroleum products produced in Venezuela. Of total exports of crude oil and refined petroleum products, 1,183 MBPD (55%) were sold to the United States and Canada. During the period from January through December 2003, according to the Petroleum Supply Monthly dated April 2004, we were the fourth largest aggregate supplier of crude oil and refined petroleum products in the United States.

Of our total crude oil exports in 2003, an aggregate of 923 MBPD (56%) were exported to the United States and Canada; 572 MBPD (35%) to the Caribbean and Central America; 88 MBPD (5%) to Europe and 65 MBPD (4%) to South America and other destinations.

Of our total refined petroleum products produced in Venezuela in 2003, approximately 432 MBPD were used in the domestic market and 502 MBPD were exported. Of the total exports of refined petroleum products in 2003, 260 MBPD (52%) were sold to the United States and Canada; 103 MBPD (20%) to the Caribbean and Central America and 139 MBPD (28%) to South America and other destinations.

The following tables set forth the composition and average prices of our exports of crude oil and refined petroleum products for the three-year period ended December 31, 2003:

PDVSA’s Export Volumes

	Year Ended December 31,
	2003		2002		2001
	MBPD	% of Total	MBPD	% of Total	MBPD	% of Total
Crude oil(1):
Light (API gravity of 30º or more)	657	40	672	38	659	32
Medium (API gravity of between 21º and 30º)	299	18	360	20	585	28
Heavy and extra-heavy (API gravity of less than 21º)	692	42	732	42	821	40
Subtotal	1,648	100	1,764	100	2,065	100

Refined products:
Gasoline/Naphtha	108	22	137	21	165	24
Distillate(2)	167	33	231	36	241	35
Low sulfur residual	—	—	—	—	3	—
High sulfur residual	134	27	149	23	189	27
Liquid petroleum gas	51	10	56	9	44	6
Other	42	8	74	11	55	8
Subtotal	502	100	647	100	697	100
Total exports	2,150		2,411		2,762

(1) Includes sales of crude oil to subsidiaries and affiliated refineries (including to the Isla Refinery in Curaçao) of 1,117 MBPD, 1,028 MBPD and 1,143 MBPD in 2003, 2002 and 2001, respectively.

(2) Includes kerosene.

The following table sets forth the average prices of our exports of crude oil and refined petroleum products from Venezuela for the three-year period ended December 31, 2003:

PDVSA’s Average Export Prices

	Year Ended December 31,
	2003	2002	2001
	($ per barrel)
Crude oil(1)	24.35	21.19	18.95
Refined products	26.53	24.23	23.94
Liquefied petroleum gas	18.84	17.65	19.55
Average for the year	24.89	21.94	20.21

(1) Includes sales of crude oil to affiliates.

The following table sets forth the geographic breakdown of our exports by types of crude oil, identifying sales to affiliates and third parties for the three-year period ended December 31, 2003:

PDVSA’s Total Crude Oil and Refined Products Export Volumes

	Year Ended December 31,
	2003			2002			2001
	(MBPD)		(% of Total)	(MBPD)		(% of Total)	(MBPD)		(% of Total)
Crude oil:
All types	1,648		100	1,764		100	2,065		100
United States and Canada	923		56	1,053		60	1,190		58
Affiliates	579		35	678		38	694		34
Third parties	344		21	375		22	496		24
Europe	88		5	134		8	151		7
Affiliates	65		4	61		4	63		3
Third parties	23		1	73		4	88		4
Caribbean and Central America	572		35	500		28	573		28
Affiliates	473		29	360		20	386		19
Third parties	99		6	140		8	187		9
South America and others	65		4	77		4	151		7
Third parties	65		4	77		4	151		7
Light (API gravity of 30º or greater)(1)	657		40	672		38	659		32
United States and Canada	273		17	256		14	273		13
Others	384		23	416		24	386		19
Medium/Heavy (API gravity of less than 30º)(2)	991		60	1,092		62	1,406		68
United States and Canada	651		40	797		45	913		44
Others	340		20	295		17	493		24
Refined petroleum products:	502		100	647		100	697		100
United States and Canada	260		52	216		33	307		44
Others	242		48	431		67	390		56
Total crude oil and refined petroleum products exports	2,150			2,411		n.a.	2,762		n.a.
Average sales price per barrel (in $):
Light (API gravity of 30º or greater)	$	27.16		$	23.46		$	22.47
Medium/Heavy (API gravity of less than 30º)	$	22.56		$	20.24		$	17.29
Refined petroleum products	$	26.53		$	24.23		$	23.94

(1) Includes condensate.

(2) Crude oils can also be classified by sulfur content (by weight). “Sour” crudes contain 0.5% or greater sulfur content (by weight) and “sweet” crudes contain less than 0.5% sulfur content (by weight). Substantially all of our exports are classified as sour crude.

The following table sets forth our consolidated sales volume of crude oil and refined petroleum products for the three-year period ended December 31, 2003:

PDVSA’s Consolidated Sales Volume

	Year Ended December 31,
	2003		2002		2001
	(MBPD)	(% of Total)	(MBPD)	(% of Total)	(MBPD)	(% of Total)
Refined petroleum products	2,371	63	2,583	59	2,586	58
Crude oil	1,413	37	1,782	41	1,892	42
Total	3,784	100	4,365	100	4,478	100
Average Price/Barrel ($/barrel)	32.08		26.56		28.21

Marketing in the United States

Sales of Crude Oil to Affiliates. We supply our international refining affiliates with crude oil and feedstocks either produced by us or purchased in the open market. Some of our U.S. affiliates have entered into long-term supply contracts with us that require us to supply minimum quantities of crude oil and other feedstocks to such affiliates, usually for 20 to 25 years. These contracts are scheduled to expire in or after 2006.

Such contracts incorporate price formulas based on the market value of a slate of refined petroleum products deemed to be produced from each particular grade of crude oil or feedstock, less certain deemed refining costs, certain actual costs, including transportation charges, import duties and taxes, and a deemed margin, which varies according to the grade of crude oil or other feedstock delivered. Deemed margins and deemed costs are adjusted periodically by a formula primarily based on the rate of inflation. Because deemed operating costs and the slate of refined petroleum products deemed to be produced for a given barrel of crude oil or other feedstock do not necessarily reflect the actual costs and yields in any period, the actual refining margin earned by the purchaser under the various contracts will vary depending on, among other things, the efficiency with which such purchaser conducts its operations during such period. These contracts are designed to reduce the inherent earnings volatility of the refining and marketing operations of our international refining affiliates. Other supply contracts between us and our U.S. affiliates provide for the sale of crude oil at market prices.

Some of the above contracts provide that, under certain circumstances, if supplies are interrupted, we are required to compensate the affected affiliate for any additional costs incurred in securing crude oil or other feedstocks. These crude oil supply contracts may be terminated by mutual agreement, by either party in the event of

a material default, bankruptcy or similar financial hardship on the part of the other party or, in certain cases, if we no longer hold, directly or indirectly, 50% or more of the ownership interests in the related affiliate.

Sales of Crude Oil to Third Parties. Most of our export sales of crude oil to third parties, including customers in the United States with which we maintain long-standing commercial relationships, are made at market prices pursuant to our general terms and conditions, and priced in dollars. Among our customers are major oil companies and other medium-sized companies. Although our general terms and conditions do not require specified volumes to be bought or sold, historically, a majority of our customers have taken shipments on a regular basis at a relatively constant volume throughout the year.

Sales of Refined Products. We conduct all our retail sales in the United States through CITGO. CITGO’s major products are light fuels (including gasoline, jet fuel and diesel fuel), industrial products and petrochemicals, asphalt, and lubricants and waxes. Gasoline sales accounted for 57% of CITGO’s total sales in 2003. CITGO markets CITGO-branded gasoline through approximately 14,000 independently owned and operated retail outlets, located throughout the United States, primarily east of the Rocky Mountains.

CITGO also markets jet fuel directly to airline customers at over 25 airports, diesel fuel in wholesale rack sales to distributors and in bulk through contract sales (primarily as heating oil in the Northeast region of the United States) or on a spot basis, petrochemicals in bulk to a variety of U.S. manufacturers as raw materials for finished goods, including sulfur, cycle oils, liquid petroleum gas, petroleum coke and residual fuel oil, asphalt to independent contractors for use in the construction and resurfacing of roadways, and many different types, grades and container sizes of lubricant and wax products.

Crude Oil and Refined Product Purchases. CITGO owns no crude oil reserves or production facilities and must therefore rely on purchases of crude oil and feedstocks for its refinery operations. We are CITGO’s largest supplier of crude oil, and CITGO has entered into long-term crude oil supply agreements with us with respect to the crude oil requirements for each of CITGO’s refineries. CITGO also purchases crude oil in the market. In addition, because CITGO’s refinery operations do not produce sufficient refined petroleum products to meet the demands of its branded distributors, CITGO purchases refined petroleum products, primarily gasoline, from third party refiners. CITGO also purchases refined petroleum products from various other affiliates, including LYONDELL-CITGO, Chalmette Refining and Hovensa, pursuant to long-term contracts. In 2003, CITGO purchased 371 MBPD of refined petroleum products under these contracts. In addition, CITGO occasionally purchases on a spot basis refined petroleum products from our Venezuelan refineries.

Marketing in Europe

We supply crude oil to our European affiliates pursuant to various supply agreements. The crude oil that we supply to our European affiliates exceeds, as a percentage of total supply, our aggregate net ownership interest in such entities’ combined refining capacity. In 2003, we supplied to the European refineries in which we held an interest, 268 MBPD of crude oil, of which 58 MBPD were exported from Venezuela and 210 MBPD were purchased in world markets.

The crude oil processed at the Ruhr Oel refineries is supplied 50% by us and 50% by Deutsche BP pursuant to a joint venture agreement and a long-term supply contract. Pursuant to these agreements, Ruhr does not acquire title to any crude oil or refined petroleum products. Instead, the crude oil supplied by us or Deutsche BP remains owned by us or Deutsche BP, as applicable, throughout the refining process. Our share of the refined petroleum products processed at the Ruhr Oel refineries is distributed through Deutsche BP’s marketing network. The operating costs of the Ruhr Oel refineries are shared equally by us and Deutsche BP.

We receive 50% of the revenues from Deutsche BP’s sales of the refined petroleum products processed at the Ruhr Oel refineries, less attributable operating and marketing costs. This arrangement effectively provides Ruhr Oel with constant break-even results. We supply crude oil to the Ruhr Oel refineries and receive revenues from the sale of refined petroleum products attributable to such crude oil.

Nynäs purchases crude oil from PDVSA and produces asphalt and naphthenic specialty oils, two products for which Venezuelan heavy sour crude oil is a particularly well suited feedstock due to its content of naphthenic, paraffinic and aromatic compounds. Asphalt products are used for road construction and various industrial purposes, while naphthenic specialty oils are used principally in electrical transformers, as mechanical process oils and in the rubber and printing ink industries. Nynäs does not own crude oil reserves or production facilities and, therefore, must purchase crude oil for its refining operations. Nearly all crude oil purchased by Nynäs is supplied by us pursuant to long-term supply contracts. We supply Nynäs only with high sulfur, extra-heavy Venezuelan crude oil.

Nynäs markets asphalt products through an extensive marketing network in several European countries. Scandinavia, the United Kingdom and Continental Europe are the source of 19%, 29% and 14%, respectively, of Nynäs’ consolidated revenues for 2003. Nynäs markets its naphthenic specialty oils throughout Europe, Africa, the Middle East and Australia, and the distillates that it produces are either sold as fuel or further processed into naphthenic specialty oils. Nynäs distributes its refined products primarily by a terminal network, specialized bitumen ships, rail tanks and trucks.

Marketing in Latin America and Caribbean

PDVSA has been strengthening a commercial strategy of integration that will allow the completion of several projects in the countries of the region, within the scope of the PetroAmerica initiative which is being promoted by Venezuela, based on the establishment of cooperation and integration mechanisms and the utilization of the resources and potentials of Latin America and the Caribbean, in order to support the socio- economic improvement of its population.

The implementation of this initiative is based on bilateral negotiations, with the intention of transferring financial resources to the people through the joint action of the states. It is also based on cost rationalization through tax and port services cost reductions and on cooperation agreements, not only for energy issues, but for education, health and infrastructure, as well.

During 2004, PDVSA supplied under special terms, crude oil and refined products to the Caribbean and Central America by means of the San José and Caracas Agreements. Furthermore, in 2005 we created PDVSA-Cuba in order to promote refining and marketing businesses in the area. In the South American market, PDVSA has been making efforts towards the strengthening of the commercial relationships with Argentina, Brazil, Uruguay, Paraguay, Ecuador and Bolivia, through the endorsement of memoranda of understanding with their national oil enterprises, with the intention of studying crude oil and refined products supply opportunities.

Marketing in Venezuela

The following table shows our sales of refined petroleum products and natural gas of the Venezuelan domestic market:

PDVSA’s Local Market Sales

	Year Ended December 31,
	2003		2002		2001
	(MBPD, except as otherwise indicated)
Refined Products:
Liquefied petroleum gas	58		59		67
Motor gasoline	209		207		225
Diesel	98		91		98
Other	67		63		68
Total	432		420		458
Natural gas (BOE)	302		324		307
Natural gas (MMCF)	1,751		1,879		1,780
Unit Sale Prices:
Refined products ($ per barrel)	$	6.61	$	6.73	$	8.74
Natural gas ($/BOE)	$	3.20	$	4.34	$	5.35
Natural gas ($/MCF)	$	0.61	$	0.71	$	0.88

Since December 1993, the Venezuelan government has permitted private sector participants to market lubricants in Venezuela.

Through our subsidiary Deltaven, we market and distribute retail gasoline and other refined petroleum products under the PDV brand in the Venezuelan local market. Deltaven is also promoting the development of the commercial infrastructure and services for retail clients with the participation of the private sector.

The retail price for gasoline is set by the Venezuelan government and represents approximately 13% of the export price for gasoline in 2003.

Since the end of 2001, three private domestic participants, Grupo Trebol, Llanopetrol and CCMonagas, and four private international participants, Shell, ChevronTexaco, ExxonMobil and British Petroleum, have been marketing their products in Venezuela. These companies market their brands through 830 retail outlets owned or operated by them, and have a market share in the gasoline and diesel sector of 53% compared to Deltaven’s 47%.

Gas

Venezuela has abundant natural gas fields. According to BP AMOCO Statistical Review of World Energy 2005, at November 2004 Venezuela was the ninth largest owner of proved reserves in the world and the largest owner of proved reserves in Latin America. These reserves were estimated at 226,000 BCF at the end of 2003, of which 150,043 BCF are proved reserves. 91% of these are associated with crude oil deposits and 9% are in the form of free gas. Our total sales of methane gas in the Venezuelan market amounted to 2,068 MMCFD by December 2003.

Petrochemicals

The Venezuelan government decided in June 2005 to transfer the activities, assets and shares held by PDVSA in Pequiven (the company’s shareholder) to the Ministry of Energy and Petroleum and to submit this transfer for approval by the Shareholder of PDVSA. The transfer is subject to the reform of the Petrochemical Act and the resolution of other legal and administrative issues.

Pequiven was established in 1977 to produce and commercialize petrochemical products in the domestic and international markets. Pequiven is organized into business units focused on three production lines:

• olefins and derivative products;

• fertilizers; and

• industrial products.

Pequiven is party to 17 joint ventures with domestic and international business partners. Most of the production facilities of these joint ventures are located at Pequiven’s complexes. We estimate that the combined production capacity of these complexes is approximately eight million tons per year.

Pequiven operates three petrochemical complexes in Venezuela:

• the Zulia–El Tablazo complex, in western Venezuela, which produces mainly olefins, chlorine or caustic soda, fertilizers, industrial feedstocks and thermoplastic resins;

• the Morón Complex, in central Venezuela, which produces fertilizers and sulfuric acid; and

• the Jose Complex, in eastern Venezuela, which produces methanol, fertilizers, industrial products and methyl terbutyl-ether (MTBE).

In addition to the three petrochemical complexes, Pequiven also has facilities to produce aromatics in the PDVSA El Palito refinery, located in the central north region of Venezuela. The gross production of Pequiven’s wholly owned plants and complexes in 2003 and 2002 was approximately 2.3 million metric tons and 3.7 million metric tons, respectively. The gross production of Pequiven’s joint ventures in 2003 and 2002 was approximately 3.9 million metric tons and 3.23 million metric tons, respectively. Products of these joint ventures include methanol, MTBE, polyethylenes, polypropylenes, ethylene oxide, ethylene glycols, caustic soda, chlorine, fertilizers, caprolactam and other specialty products.

Pequiven’s goals are to increase the production of our petrochemical products and promote growth in this sector by increasing the sales of petrochemical products domestically. It is expected to achieve an annual combined production capacity of 12.0 million metric tons by 2006 at Pequiven’s plants and through Pequiven’s joint ventures. Pequiven also will continue to focus on improving competitiveness (especially in the Latin American market) and profitability of the natural chemical and petrochemical sector.

In this regard, Pequiven continuously explores new projects and joint ventures with third parties. Currently there are in discussions with potential partners regarding the development of the Jose Complex. To date, Pequiven’s joint ventures have allowed it to establish a significant and growing presence in regional and international markets. In 2003, North America remained Pequiven’s largest export destination followed by South America, Europe and Asia, and Central America and the Caribbean.

The following table sets forth Pequiven’s sales, consolidated revenues, net property, plant and equipment and capital expenditures in its wholly owned plants for each of the years indicated:

Pequiven’s Sales, Consolidated Revenues, Net Property, Plant and Equipment and Capital Expenditures

	Year ended December 31,
	2003	2002	2001
	($ in millions, except as otherwise indicated)
Sales volume (thousands of metric tons)	2,734	4,127	4,167
Consolidated revenues (1)	784	919	1,070
Net property, plant and equipment at year end	1,808	1,925	2,221
Capital expenditures	48	53	46

(1) Includes $492 million, $268 million and $351 million of sales to affiliates for 2003, 2002 and 2001, respectively; and sales to PDVSA’s subsidiaries, which are eliminated in our consolidated financial statements.

Extra-heavy Crude Oil

Previously our subsidiary Bitor was developing reserves of approximately 429 million of metric tons of extra-heavy crude oil (or approximately 2,690 million barrels) principally through a process of emulsifying natural extra-heavy crude oil in water to create an alternative liquid fuel to generate electricity, which we refer to as Orimulsion®. However, PDVSA decided to apply most of these reserves to the production of commercial crude oil, minimizing the production of Orimulsion®. This new scheme is part of an effort to develop a financially balanced strategy for our natural extra-heavy crude oil production.

In December 2001, Bitor, China National Oil and Gas Exploration and Development Corporation and Petrochina Fuel Oil Company Limited formed a joint venture called Orifuels Sinoven, S.A. with the view to building and operating a production facility capable of producing up to 6.5 million metric tons by 2006. Orifuels Sinoven, S.A. is developing production facilities in two locations in Venezuela; Morichal facilities were approximately 30% complete and the Jose plant was approximately 80% complete by June 2005.

Due to this new approach to the extra-heavy crude oil business, we have decided to call off all other production facilities development plans. We expect to complete the Orifuels Sinoven complex by October 2005 and once it is operational, this will be our exclusive Orimulsion® manufacturing facility. From the production of this complex, Bitor will supply directly its Orimulsion® supply agreements.

Our Orimulsion® production capacity is currently 6.5 million metric tons per year (or approximately 41 million barrels per year). Our net production in 2003 was approximately 5.2 million metric tons (or 35 million barrels), as compared to 5.4 million metric tons (or 37 million barrels) in 2002.

PDVSA’s 2003 production was sold as follows:

Geographic location		% of sales
Italy		36
China		30
Canada		13
Japan		10
Korea		7
Others		4

The following table sets forth certain production, revenue and capital expenditure figures relating to our Orimulsion® business for the periods indicated:

	Year ended December 31,
	2003	2002	2001
Raw material production (thousands of metric tons)	3,426	4,041	4,257
Production (thousands of metric tons)	5,175	5,451	6,226
Orimulsion sales volume (thousands of metric tons)	5,201	5,575	6,173
Consolidated revenues ($ in millions)	186	186	200
Net property, plant and equipment ($ in millions)	537	544	561
Capital expenditure ($ in millions)	18	9	43

Coal

At a PDVSA Board of Directors’ Meeting held on October 3, 2003, it was decided to accept the terms for transferring activities, assets and shares held by PDVSA in Carbozulia to Corporacíon de Desarrollo de la Región Zuliana (Corpozulia). The transfer of all rights of ownership to shares that PDVSA held in Carbozulia to Corpozulia was published in Official Gazette dated February 2, 2004.

The following table sets forth Carbozulia’s share of coal production, sales and revenues for each of the periods indicated:

Carbozulia’s Production, Sales and Consolidated Revenues

	Year Ended December 31,
	2003	2002	2001
	(thousands of metric tons, except as otherwise indicated)

Coal production	6,808	7,859	7,571
Coal sales volume	7,570	7,361	7,627
Consolidated revenues ($ in millions)	145	160	164

Carbozulia’s total coal production is exported, primarily to the United States, Canada, Italy, France, Holland, Sweden, Germany, Puerto Rico and Brazil.

Overview of Main Projects 100% Owned by PDVSA

The Anaco Gas Project

The objective of the Anaco Gas Project is to satisfy the internal demand for gas. This project includes designing and building the facilities anticipated to yield a production of 2,400 MMCFD of gas and 35 thousand barrels per day of associated light crude oil when completed. The project is being developed in two phases, with start up operations (Phase I) capable of producing 2,016 MMCFD of gas, anticipated to commence in 2007. We expect the production capacity of this project to reach 2,400 million MMCFD of gas by 2008 (Phase II). The total estimated capital investment for this project is $732 million.

In a probable Phase III, project installations will reach a production capacity of 2,700 MMCFD of gas, according to PDVSA’s Opportunities Portfolio 2003-2022.

The ICO Project

The objective of this project is to connect Venezuela’s central and eastern (Anaco-Barquisimeto) and western (Ule-Amuay) natural gas transmission systems with a view to:

• facilitate the supply of gas to the western region of Venezuela;

• expand the delivery of gas to other regions and cities within the country; and

• promote industrial and commercial development in the areas along the gas transmission pipeline to be built in connection with this project.

We expect to construct 300 km of gas pipeline of 36-inch & 30-inch, running from Morón to Río Seco and three compression stations. This project has two phases; Phase I includes construction of 70 km of a 36-inch diameter gas pipeline running from Quero to Río Seco and five (5) automatic valve stations; Phase II includes construction of 230 km of a 30-inch diameter gas pipeline running from Quero to El Manglar and three (3) compression stations located at Altagracia, Los Morros and Morón. The engineering of Phase I was completed by the end of the third quarter 2003; the construction of this Phase was completed by the end of the first quarter of 2005. With respect to Phase II, the construction of 112 km of a 30-inch diameter gas pipeline will be completed by the end of 2005; the construction of the compression stations will start in the fourth quarter of 2005. This infrastructure allows a gas supply ranging between 450 and 520 MMCFD, with an installed capacity of 155,000 Horse Power ISO at different levels of discharge pressure between 1,000 and 1,200 pounds per square inch.

We expect to invest approximately $413 million in this project, anticipating its completion by December 2007.

The Jose 250 Project

The main purpose of this project is to provide all the required infrastructure for gas conditioning and processing of the associated gas produced from the operational Eastern Areas of Anaco (San Joaquín) and North of Monagas (Jusepín and Pirital), to satisfy domestic market demand and supply injection gas for secondary oil recovery processes of North Monagas oil fields.

We expected to build three new Liquid Extraction Plants with a total capacity to process 2,350 MMSCFD, one fractionation unit with capacity to fraction 50,000 BPD of LNG, expansion of the marine terminal of the Jose Condominium and construction and expansion of LNG pipelines. Phase I of the project will be completed in 2007 and Phase II in 2008. We will have an additional production of 32 MBPD of LNG in 2007, reaching a total of 75 MBPD of LNG in year 2008. In 2005 the engineering studies continue to progress. The estimated total investment for the project is $664 million.

The Western Cryogenic Project

The development of the Western Cryogenic Complex (WCC) is one of the main projects included in the 2005 - 2010 Business Plan of PDVSA-Western Division. Its objective is to optimize the natural gas scheme processing in the Western region of Venezuela by increasing the ethane and LNG production. This project is expected to reduce significantly the operation and maintenance costs of current plants, allowing a better expansion of the gas business in the area.

The proposed scheme will yield a production of 35 MBPD of Ethane for Pequiven – El Tablazo and 70 MBPD of LNG, decreasing substantially the country’s western processing cost and promoting the LNG business growth.

The estimated capital investment for the project is $600 million. Main facilities include two extraction trains, each with a capacity of 475 MMSCFD of gas, one gas fractionating train with installed capacity of 35 MBPD and offsite facilities.

The Integral Ceuta-Tomoporo Project

The main purpose of the Integral Ceuta - Tomoporo project is to maximize the recoverable crude oil reserves value of Ceuta – Tomoporo, through exploiting the B-superior Eocene formation, which has estimated reserves of 1,000 million barrels of 23.6° API crude oil. The reservoir was discovered in 1988.

This project also has an impact on the sustainable economic development of its area of influence. Our 2005-2010 business plan activities include drilling 6 vertical and 47 inclined producing wells, together with 21 injector wells. In 2004 we drilled 3 vertical and 7 inclined wells. In 2005 we will construct one flow station, 21 Km of crude oil and gas pipelines, roads and a cluster platform. Total investment costs throughout project life (2004-2021) will be approximately $1,200 million, with an average crude oil production of 90 to 277 MBPD. Net present value expected from this project totals $3,257 million. By December 2003, total investments totaled $28 million.

Transportation and Infrastructure

Pipelines and Storage

Venezuela and the Caribbean. We have an extensive transportation network in Venezuela consisting of approximately 3,113 km in total of crude oil pipelines (over 28 pipelines), with a throughput capacity of approximately 6,340 MBPD of crude oil. These pipelines connect production areas to terminal facilities and refineries. We have a network of gas pipelines in Venezuela totaling approximately 3,781 km, with a throughput capacity of 2,748 MM3D. Our network is comprised of the Western and East Central systems, stretching from Lake Maracaibo, in the Zulia state to Punto Fijo, in the Falcón state and from Puerto Ordaz, in the Bolívar state to Barquisimeto, in the Lara state. We also have a network of 1,179 km of products pipelines with a total flow capacity of approximately 831 MBPD.

We maintain total crude oil and refined products storage capacity of approximately 30 MMB and 74 MMB in Venezuela, respectively, including tank farms, refineries and shipping terminals, of which approximately 16.3 MMB is available at our refineries. Our terminal facilities are comprised of nine maritime ports as well as two river ports. A new terminal facility was completed at the Jose Complex in 2003.

In addition to the storage and terminal facilities in Venezuela, we maintain storage and terminal facilities in the Caribbean, located in Bonaire, the Bahamas, Trinidad, Curaçao and St. Eustatius, with an aggregate storage capacity of 50 MMB as of December 31, 2003. The Curaçao oil terminal, which is leased from the Netherlands Antilles government, had a storage capacity of approximately 15 MMB at December 31, 2003.

United States. CITGO owns and operates a crude oil pipeline and three products pipeline systems. CITGO also has equity interests in three crude oil pipeline companies and six refined product pipeline companies. CITGO’s pipeline interests provide it with access to substantial refinery feedstocks and reliable transportation to the refined

product markets, as well as cash flows from dividends. One of the refined product pipelines in which CITGO has an interest, Colonial Pipeline, is the largest refined product pipeline in the United States, transporting refined products form the Gulf Coast to mid-Atlantic and Eastern seaboard states.

Europe. Through equity interests in five European pipeline companies, we have interests in four crude oil terminals and four crude oil pipelines in northwestern Europe, including two pipelines from the Mediterranean coast to Germany. We also own three port facilities in the Rhine-Herne Canal providing barge access to Rhine and North Sea coastal ports.

Shipping

At December 31, 2003, PDV Marina, a wholly owned subsidiary of PDVSA, owned and operated 21 tankers with a total capacity of approximately 1,347 MDWT and an average age at December 31, 2003 of approximately 14 years.

During 2003, average shipments of crude oil and refined petroleum products amounted to approximately 1,111 MBPD, of which 436 MBPD were shipped by our own tankers and the remainder by chartered tankers.

PDVSA achieved the certification of its ships and docks to the International Safety Code of Ships and Port Installations, which entered in effect on July 1, 2004. Accordingly, we carried out a project which included risk evaluations, training, and equipment procurement, among other tasks and have spent about $5 million to date. The certifications can be seen at http://www2.imo.org/ISPSCode.

Research and Development

Intevep is our wholly owned subsidiary responsible for research and technology support. Its overall mission is to create and sustain a competitive advantage for PDVSA through efficient and effective development, adaptation and application of technology. Intevep contributes substantially, through application of technology, toward exploration for new oil and gas reserves, better utilization of existing reserves, increasing production, reduction in operational costs, greater productivity, upgrading processes for heavy and extra-heavy crude oil, improvements in product quality, improvements in health and safety standards and the development of new petroleum-derived products and innovative processes.

During 2003, we continued to develop products and technologies such as DISOL® (Gas-to-Liquid technology) and new improvements in the DISOL catalyst were obtained. Additionally, a pilot plant was designed to be built at Intevep next year. AQUADIESEL®, a low emission diesel for public transportation, was successfully tested in Houston, Texas, US. Additionally, cost reductions in this micro-emulsion formulation were achieved. Further progress was made in the development of AQUACONVERSION®, a catalytic process used to produce synthetic crude from Morichal heavy oil. Two commercial units of ISAL® technology started up in the USA. The basic engineering of two DHDV units for reducing sulfur in diesel and the visualization study of a HDHPLUS® unit at the Puerto La Cruz refinery were completed.

Environmental and Safety Matters

Environmental

The majority of PDVSA’s subsidiaries, both in Venezuela and abroad, are subject to various environmental laws and regulations under which they may be required to make significant investments and expenditures to modify their facilities and to prevent or remedy the environmental effects of waste disposal and spills of pollutants. In the United States and Europe, our operations are subject to various federal, state and local environmental laws and regulations, which may require them to take action to remedy or minimize the effects on the environment from our operations of earlier plant decommissioning or leakage of pollutants.

throughout the company and full deployment of this System is expected to be completed by 2006. This management system is based on international practices and standards, such as ISO 14001 for Environmental Management; ISO 18000 and British Standard BS 8800 for health and Occupational Safety, and OSHA’s and American Petroleum Institute (API)’s 750 for process safety. PDVSA has already invested $16 million and is expected to invest an additional $30 million to complete full implementation of its Risk Management System. In addition, PDVSA has an investment plan to comply with the applicable environmental regulations in Venezuela. This investment plan contemplates approximately $2,255 million in capital expenditures from 2004 through 2009, including the following: $1,150 million for product quality; $911 million for risk control at operating sites; $162 million for environmental compliance projects; and $32 million for other environmental-related investments. Also, there is a plan to remediate a total of 13,973 oil pits to temporality store oil sludge and/or drilling cuts. The plan has an expected duration of 12 years and started in 2001. As of December 2003, a total of 3,417 petroleum pits have been remediated. The overall plan is to recover and to recycle the disposed waste, including abandoned installations, and to transform those areas into useful assets. PDVSA will spend approximately $408 million to complete the project from 2004-2012. (See note 20 to our consolidated financial statements, included in Item 18. Financial Statements).

CITGO estimates expenditures of approximately $785 million for environmental and regulatory capital projects from 2004 through 2008. During 2003, PDVSA spent approximately $59 million in Venezuela and CITGO spent approximately $253 million for environmental and regulatory capital improvements in its operations.

The oil industry sabotage and operational stoppage in December 2002 and the first months of 2003 caused effects on the environment which, although difficult to quantify and to evaluate, did impact negatively the surroundings of our wells, plants and other facilities, with an economic impact due to damage remediation actions. (See note 21 to our consolidated financial statements, included in Item 18. Financial Statements).

During 2003, the Water Treatment Plant at El Tablazo Complex, Maracaibo, Zulia state became operational. This water is to be used as industrial water for El Tablazo, avoiding the discharge of 1,300 lts/sec of sewage water to the Maracaibo Lake. Those amounts represent 13% of the total sewed water discharged from the City of Maracaibo, contributing to the remediation of the Maracaibo Lake.

CITGO has received various notices of violation from the Environmental Protection Agency (EPA) and other regulatory agencies, which include notices under the federal Clean Air Act, and could be designated as Potentially Responsible Parties (“PRPs”) jointly with other industrial companies with respect to sites under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA). These notices are being reviewed and, in some cases, remedial actions are being undertaken, and in others, CITGO is engaged in settlement negotiations.

Conditions that require additional expenditures may exist at various sites including, but not limited to, our operating complexes, closed refineries, service stations and crude oil and petroleum storage terminals. Based on currently available information we cannot determine the amounts of any such expenditure. Management believes that these matters, in the normal course of operations, will not have a material effect on the financial position, liquidity or operations of PDVSA.

Safety

Due to the nature of our business, our operating subsidiaries and joint ventures are subject to stringent occupational health and safety laws in the jurisdictions in which they operate. As such, each of our subsidiaries and joint ventures maintains comprehensive safety, training and maintenance programs with the help of international and recognized leading authorities in this area. Our management believes that our activities are conducted substantially in compliance with all applicable laws.

4.C Organizational structure

PDVSA was formed by the Venezuelan government in 1975, and conducts its operations through its Venezuelan and international subsidiaries.

Through December 31, 1997, we conducted our operations in Venezuela through three main operating subsidiaries, Corpoven, S.A., Lagoven, S.A. and Maraven, S.A. In 1997, we established a new operating structure based on business units. Since then, we have been involved in a process of transforming our operations with the aim of improving our productivity, modernizing our administrative processes and enhancing the return on capital. The transformation process involved the merger of Lagoven, S.A. and Maraven, S.A. into Corpoven S.A., effective January 1, 1998, and renaming the combined entity PDVSA-P&G. In May 2001, we renamed PDVSA-P&G “PDVSA Petróleo” and by the end of 2002, certain of our nonassociated gas assets were transferred to PDVSA Gas.

Additionally, we have also made several adjustments within our organization in order to enhance internal control of our operations, to improve on our governance model and to align our operating structure with the long-term strategies of our shareholder. These adjustments consist primarily of the adoption of a new framework of operating structure that increases the involvement of our board of directors in our activities, and, at the same time, enhances PDVSA’s operational independence.

Below is a summary of the significant changes that have ocurred within our main subsidiaries and affiliates:

PDVSA Petróleo: This is the core business of PDVSA. Its operations have not suffered changes and only its administrative structure has been adjusted. The most significant changes for this affiliate is the restructuring of the corporate units of Exploration, Production, Refining, and Marketing and Supply.

Carbozulia: In February 2004 net assets of this company amounting to $91 milllion were transferred to Corpozulia “Corporación de Desarrollo de la Región Zuliana”, a fund promoting regional development. PDVSA still holds some guarantees related to two joint venture agreements (Carbones del Guasare and Carbones de la Guajira) previously established by Carbozulia.

Palmaven: This affiliate was completely transformed. Its new role is to promote the national social development through educational, health and job creating initiatives, directed to the poorest sectors of the Venezuelan society. Its previous activities related to environmental services were transferred to the HSE (health, safety and environment) organizations of other operating affiliates and the participation of Palmaven in 14 agricultural joint ventures are being evaluated in order to be sold or transferred.

Bitor: Its Board of Directors has been instructed to minimize the production of Orimulsion®, to complete the production facilities of its joint venture Orifuels Sinoven, to comply with its supply agreements and to close its international marketing joint ventures. Its personnel are being transferred to PDVSA Petróleo. PDVSA from now on will apply most of these reserves to the production of extra-heavy crude oil.

Cied: This non-profit association used to provide training services to the different affiliates of PDVSA. Currently, this function has been decentralized and affiliates are free to contract their training services. Its personnel were redistributed to other organizations within PDVSA.

PDVSA Trading: This affiliate was created to manage commodity price risk associated with crude and refined products businesses. It has been deactivated due to a redefinition of PDVSA’s refining and marketing strategy. Some administrative steps are being taken prior to its definitive closure.

PDVSA Gas: Since August 2003 the gas production activities and the strategic projects Plataforma Deltana, Mariscal Sucre and Cigma have been delegated to the PDVSA’s Exploration and Production division, whereas the LNG activities have been delegated to PDVSA’s Refining division. Some administrative and operating activities and personnel of PDVSA Gas are being moved to the eastern region of the country.

CVP: This affiliate continues managing all matters related to mixed enterprises such as The Orinoco Belt Joint Ventures, Risk Sharing Agreements, Operating Agreements and P&GI Investments. Additionally, it has a new responsibility regarding the administration of “FONDESPA”, a trust created to finance social projects, which will be funded by extraordinary revenues coming from higher oil prices.

Interven: This affiliate was reorganized in order to manage all business derived from the Cooperation Agreement signed between Argentina and Venezuela. PDVSA began working with the Argentinean energy company Enarsa, to evaluate upstream and downstream business opportunities in Argentina. Additionally, the Board of Directors of PDVSA in its April 7, 2005 meeting decided to transfer the businesses of Citgo Latinoamerica (CILA) to Interven in order to support a strategy of regional integration. The day-to-day activities of CILA are being performed by the international sales management of our corporate supply and marketing division.

Pequiven: According to a Presidential Decree published on June 2005, Pequiven will be transferred to the Ministry of Energy and Petroleum. The completion of this transfer will depend on the reform of the Ley De Estimulo Al Dearrollo De Las Actividades Petroquimica, Carboquimica y Similares, or the Petrochemical Law, and other legal and administrative issues.

Isla Refinery: PDVSA has initiated studies to determine the profitability of this business, investments required to improve the process capacity and to meet regulatory and product quality demands. These studies are being utilitzed to align the performance of Isla Refinery with national strategic guidelines and PDVSA’s business plan and to streamline its business processes.

Deltaven: This affiliate distributes refined products within the domestic market. It maintains its own distribution network and has positioned itself well with wholesalers and retailers. Its strategy includes gaining better position within the distribution chain through improvements of its service stations and truck float.

International subsidiaries: We are currently reviewing our international assets strategic and financial performance. In this sense, we are evaluating the net contribution to PDVSA of our affiliates CITGO, Ruhr Oel, Nynas, BORCO, BOPEC, Isla Refinery, in order to optimize the return of our international portfolio. This evaluation of our international subsidiaries might lead to restructurings, merges, divestures or acquisitions in the near future.

For the time being, PDVSA’s board of Directors is not considering any further changes of its organizational structure.

Our most important subsidiaries and affiliates at December 31, 2003 and our percentage of equity capital (to the nearest whole number) are set out below. The principal country of operation is generally indicated by the companies country of incorporation:

Companies	% Ownership	Principal Activities	Country of Incorporation
AB Nynäs Petroleum	50	Refining and marketing	Sweden

Bonaire Petroleum Corporation N. V.	100	Storage	The Netherlands Antilles

Chalmette Refining, L.L.C.	50	Refining	United States

CITGO Petroleum Corporation	100	Refining, marketing and transportation	United States

Corpoguanipa, S.A.	100	Production, upgrading and marketing	Venezuela

Corporación Venezolana del Petróleo, S.A.	100	Exploration and production	Venezuela

Deltaven, S.A.	100	Marketing (in Venezuela)	Venezuela

Hovensa, L.L.C.	50	Refining	U.S. Virgin Islands

Intevep, S.A.	100	Research and development	Venezuela

LYONDELL-CITGO Refining Company, L.P.	41	Refining	United States

PDV America, Inc.	100	Refining, marketing and transportation	United States

PDV Europa B.V.	100	Refining and marketing	The Netherlands

PDV Holding, Inc.	100	Refining, marketing and transportation	United States

PDV Insurance Company Ltd.	100	Insurance	Bermuda

PDV Marina, S.A.	100	Shipping	Venezuela

PDV Midwest Refining, L.L.C.	100	Refining and marketing	United States

PDVSA Cerro Negro, S.A.	100	Production, upgrading and marketing	Venezuela

PDVSA Finance Ltd.	100	Financing	The Cayman Islands

PDVSA Gas, S.A.	100	Gas production, processing and distribution	Venezuela

PDVSA Petróleo, S.A.	100	Integrated oil operations	Venezuela

PDVSA Sincor, S.A.	100	Production, upgrading and marketing	Venezuela

Petroquímica de Venezuela, S.A.	100	Chemicals and petrochemicals	Venezuela

Petrozuata, C.A.	49.9	Production, upgrading and marketing	Venezuela

Ruhr Oel GmbH	50	Refining and marketing	Germany

The Bahamas Oil Refining Company International Limited	100	Storage	The Bahamas

Item 4.D Property, plants and equipment

See generally our discussion in “Item 4.B Business overview.”

Item 5. Operating and Financial Review and Prospects

Effects, Losses and Damages resulting from the Work Stoppage and Other Events in the Petroleum Sector

During December 2002 and the first months of 2003, a series of national events significantly interrupted the economic activities in Venezuela. Concurrently, a substantial group of workers from PDVSA and its Venezuelan subsidiaries abruptly initiated a work stoppage that interrupted the Company’s normal, ongoing operations in Venezuela, which continued despite requests made by management of the Company in the local media for them to return to their positions. PDVSA is of the opinion that this interruption of the activities, and related actions, constituted sabotage, and accordingly the Company has referred the matter to the competent authorities, including the General Prosecutor of the Republic, to establish responsibility for the damage resulting from these actions.

As stated, these events resulted in losses and damages, as well as a reduction in the country’s economic activities. The economic performance of PDVSA significantly affects some of the economic variables of the country, among others the gross domestic product (GDP), the generation of foreign exchange and the collection of taxes and other contributions (approximately 18%; 67% and 57%, approximately, of the national totals for the year ended December 31, 2003). Studies performed by the Ministry of Finance and the Central Bank of Venezuela (BCV) indicate that the

reduction in activities of the country had an impact on the economy during the abovementioned period, including among others:

• GDP decreased by 15.8% during the fourth quarter of 2002, and by 24.9% during the first quarter of 2003. In both quarters, the principal effect on the local economy was in the petroleum sector, where GDP fell by 25.9% and 39.3%, respectively.

• There was a significant reduction in the country’s fiscal income, which limited the capacity of the National Executive to execute its plans and programs.

• There was a reduction in international reserves and funds held with the FIEM. After this reduction the National Executive, together with the BCV, implemented exchange controls, with a view to limiting the negative effects on the local economy.

The interruption of the activities of PDVSA and its Venezuelan subsidiaries from December 2002, due to the absence of its workers, in spite of the numerous requests by management of PDVSA for them to return to their positions, resulted in an abrupt and significant interruption to PDVSA’s operations, resulting in losses and damages to PDVSA’s installations and affecting the various activities of the Company.

Also, these events resulted in a significant reduction in PDVSA’s production of oil and natural gas, mainly in its principal subsidiary, PDVSA Petróleo; as well as a reduction in the exports of crude oil and products from Venezuela. Presented below is a comparison of the export volumes of PDVSA Petróleo for 2003, 2002 and 2001:

(a) Comparison of PDVSA’s Export Volumes:

Month	2003 (1)	2002 (1)	2001(2)
January	15,535	81,841	93,580
February	30,380	73,424	82,980
March	62,055	74,527	92,567
April	66,734	59,595	82,843
May	51,481	66,501	86,470
June	108,028	74,467	82,833
July	65,973	85,352	90,853
August	70,344	89,638	86,880
September	62,610	82,691	79,035
October	82,475	87,754	83,981
November	68,326	74,823	81,191
December	76,777	19,860	83,058
Total	760,718	870,473	1,026,271

(1) The work stoppage commenced in December 2002 and continued into 2003.

(2) The management of PDVSA has determined that 2001 is the base year, as it was not affected by the work stoppage.

(b) Average Price per Barrel of Exports

		2003		2002		2001
Average price (US$ per barrel)		24.78		21.84		20.14

During the period that operations were interrupted, the Venezuelan government authorized PDVSA to purchase petroleum and diesel on the international market in order to meet the needs of the local market. These purchases were made at international prices, which were substantially higher than sales prices in the local market. The difference between the international purchase prices and the related sales prices realized in Venezuela resulted in an unfavorable effect for the Company in 2003 of approximately $504 million.

The previously described events resulted from an unprogrammed interruption of the majority of the basic operations of PDVSA and its subsidiaries in Venezuela. These events caused damages to the upstream and downstream installations requiring repair and remediation, and caused significant losses, particularly with respect to the condition of oil reservoirs and wells and also refineries, pipelines and terminals that needed to be repaired or remedied. Based upon an evaluation made by PDVSA, the total costs indentified with these damages and losses were approximately $209 millon.

All costs and expenses relating to these events, identified on the basis of the information available, were charged to PDVSA’s results of operations in 2003.

Below is a summary of some of the damages to the installations and equipment, based on reports prepared by the Company’s management and approved by the Board of Directors.

Exploration, Production and Improvement

Some of the principal effects on PDVSA’s infrastructure were: damages to some information systems controlling certain operating activities related to productive oil wells; deterioration of operating equipment as well as instrumentation systems, well automation booths, electrical flow, dashboards and pumping systems, which interrupted production activities and delayed the restoration of operations. Some of these damages required the acquisition of new equipment and the implementation of special procedures to restore the production of crude oil and gas.

Refining, Supply and Marketing

The unscheduled stoppage of refineries caused damages and the malfunctioning of some equipment, which delayed their start-up and affected their operating capacity, mainly in the refineries located in the state of Falcon. Among the affected equipment was the sulphur recovery unit No. 3 at the Amuay refinery, the catalytic cracking plant at the Cardon refinery and the flexicocker unit at the Amuay refinery. Also, losses resulted from the payment of demurrage and penalties resulting from the anchoring of owned vessels and third party vessels at Venezuelan ports.

Other Effects on the Operations of PDVSA and its Venezuelan Subsidiaries

The work stoppage of operations also caused other effects that, although they cannot be quantified or valued accurately significantly affected the operations of PDVSA and its Venezuelan subsidiaries. Among others there were delays to the environmental remediation plans; the loss of sensitive operating information; interruption of the information systems; delays in compliance with obligations with creditors; a deterioration of PDVSA as a reliable supplier of oil; failure to comply with financial, legal and contractual obligations; loss of market share; delays in the execution of plans and projects; and the loss of human resources and intellectual capital with an average specialized experience of 15 years.

In addition to the effects and loss from damages resulting from the work stoppage on the Company’s operations, the financial and administrative systems in general were significantly affected. Consequently, there were weaknesses in the internal controls which affected the processing of financial and operational information of PDVSA and its Venezuelan subsidiaries, during December 2002 and an important part of 2003. During the affected period, PDVSA

implemented alternative control systems and, among other actions, concentrated its efforts on filling key managerial positions and hiring and training new personnel to take charge of the information, financial, administrative and operating systems. The above resulted in delays in certain important accounting processes, impeding and delaying the delivery of financial reports both internally and externally.

The Company’s management has as one of its principal objectives, continuing the plan to fully restore the Company’s operations, and resolving other outstanding matters resulting from these events. Measures taken include, among others, strengthening the Company’s Exploration, Production and Improvement, Refining, Supply and Marketing activities; strengthening the management structure of domestic and international businesses; executing a training plan for personnel working in the operating, administrative and financial areas; creating teams specialized in technology in order to implement an integrated financial information system; implementing a plan for the comprehensive evaluation and improvement of the internal control structure, as well as hiring external advisors for those activities required to support PDVSA’s operations.

Overview and Trends

Our consolidated financial results depend primarily on the volume of crude oil produced and the price levels for hydrocarbons. The level of crude oil production and the capital expenditures needed to achieve such level of production have been among the principal factors determining our financial condition and results of operations since 1990, and are expected to continue to be the principal factors in determining our financial condition and results of operations for the foreseeable future.

Historically, members of the OPEC have entered into agreements to reduce their production of crude oil. Such agreements have sometimes increased global crude oil prices by decreasing the global supply of crude oil. Venezuela is a party to and has complied with such agreements, and we expect that Venezuela will continue to comply with such production agreements with other OPEC members. Since 1998, OPEC’s production quotas have resulted in a worldwide decline in crude oil production and substantial increases in international crude oil prices.

During 2003, the OPEC basket increased by $3.74 per barrel, or 15%, from $24.36 per barrel in 2002 to $28.10 per barrel in 2003. The average price of our exports, including refined products, increased by $1.74 per barrel, or 14%, from $21.94 per barrel in 2002 to 24.89 per barrel in 2003.

Our total OPEC production quota increased from 2,497 MBPD in December 2002 to 2,647 MBPD in December 2003. Venezuela’s OPEC production quota increased by 460 MBPD to 3,107 MBPD at December 2004. By December 2004, the average price of the OPEC basket was $36.04 per barrel and the average price of the Venezuelan basket was $32.61 per barrel. In July 2005 our quota was raised to 3,223 MBPD and the OPEC basket reached $53.82 per barrel and the average price for six months of the Venezuelan basket reached $48.94 per barrel.

Impact of Inflation and Devaluation

While more than 95% of our revenues and a significant portion of our expenses are in dollars, some of our operating costs (including income tax liabilities) are incurred in bolivars. As a result, our financial condition and results of operations are affected by the Venezuelan inflation rate and the timing and magnitude of any change in the $/Bs exchange rate during a given financial reporting period.

Since 1998, the Venezuelan government has used exchange rates to moderate inflation, by devaluing the bolivar within a pre-determined band. Effective February 13, 2002, however, the Venezuelan government and the BCV adopted a floating exchange rate system, as opposed to the band system previously in effect. As a result of the adoption of a floating exchange rate system, the bolivar devalued substantially against the dollar and inflation accelerated in 2002. During 2002 and 2001, we experienced devaluation of the bolivar at an annual rate of 82% and 10%, respectively, and an annual inflation rate of 31% and 12%, respectively.

On February 5, 2003, the Venezuelan government established an exchange control regime, and fixed the exchange rates for the sale and purchase of foreign currency at Bs1,600.00 to $1 and Bs1,596.00 to $1, respectively.

The annual devaluation rate for 2003 was 14% and the inflation rate was 27%. On February 7, 2004 a new foreign exchange rate for the sale and purchase of foreign currency was established at Bs. 1,920.00 to $1 and Bs. 1,915.20 to $1, respectively. The new exchange controls do not have a significant impact on PDVSA’s operations because we and our affiliates are exempt from foreign exchange controls, up to a specified dollar limit. See notes 3 and 22 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Summary of Exchange Rates (Bs/$1)

	December 31,
	2004	2003	2002	2001
Exchange rates at year-end derived from exchange agreement with the BCV (Bs/$1) (see note 2 to our consolidated financial statements)	1,920.00	1,600.00	1,403.00	770.09
Average annual exchange rates (Bs/$1)	1,920.00	1,611.32	1,163.91	722.01
Interannual increments in the exchange rate (%)	20.00	14.04	82.18	10.29
Interannual increments in the CPI* (%)	19.18	27.10	31.22	12.29

* Consumer Price Index

Impact of Taxes on Net Income and Cash Flows

In accordance with Venezuelan income tax law, our income tax expense is based on our Bolivar accounting records. For fiscal purposes, Venezuelan companies are required to reflect the impact of inflation and the variations in the rate of the bolivar relative to the dollar and other foreign currencies by adjusting non-monetary assets and stockholder’s equity on their fiscal balance sheets. The Venezuelan income tax law considers any gain resulting from this adjustment as taxable income and any loss as a deductible expense. Such adjustments affect our taxable income and therefore the amount of our income tax liability in bolivars. When such tax liabilities are translated into dollars, the adjustments may create a material difference between the effective tax rate paid when expressed in dollars and the statutory rate in bolivars.

The following is a summary of the changes included in the new Organic Hydrocarbons Law that affect taxes levied on PDVSA’s operations:

• Production tax. Venezuela’s new Organic Hydrocarbons Law that came into effect in January 2002, which, among other things, increased the production tax rate from 16²/₃ % to 30% based on the volume of extracted hydrocarbons. For mature reservoirs or extra-heavy crude oil from the Orinoco Belt, a tax rate within a 20% to 30% band was established. For natural bitumen, a tax rate within a 16²/₃ % to 30% band was established, based on the profitability of reservoirs. This tax is fully deductible in determining net taxable income.

• Surface tax. This tax is calculated at the annual rate of 100 tax units for each square kilometer or fraction thereof. Surface tax is determined based on the concession area not under production, with an annual increase of 2% for five years and 5% in subsequent years.

• General consumption tax. This tax is determined at a rate ranging between 30% and 50% of the price paid by the final customer, is applicable to each liter of hydrocarbon-derived product sold in the domestic market. The consumption tax rate is determined annually.

• PDVSA also is taxed on its own consumption, equivalent to 10% of the value of each cubic meter of hydrocarbon-derived product consumed as fuel oil in its operations, calculated based on the final sale price.

Income taxes. In January 2002, an amendment to the Venezuelan income tax law came into effect, reducing the income tax rate applicable to our Venezuelan subsidiaries engaged in the production of hydrocarbons and related activities from 67.7% to 50%.

By August 2004, Venezuela levied a wholesale tax (a form of value added tax) on domestic sales transactions of 16%, however, until October 1, 2005 this tax was levied at a rate of 15% and currently the rate is 14%.

As an exporter, each of our Venezuelan operating subsidiaries is entitled to a refund for a significant portion of such taxes paid, which we classify on our balance sheet as recoverable value added tax. The Venezuelan government reimburses taxes through special tax recovery certificates, or CERTS. In 2001, we recovered $209 million of CERTs, and none during 2002 and 2003.

PDVSA and some of its Venezuelan subsidiaries are entitled to a tax credit for new investments in property, plant and equipment of up to 12% of the amounts invested. In the case of PDVSA Petróleo, such credits, however, may not exceed 2% of its annual net taxable income and, in all cases, the carryforward period may not exceed three years.

Venezuela also levies a tax on corporate assets at a rate of 1% of the average value of a company’s assets, as adjusted for inflation at the beginning and at the end of each year. The tax is in effect a minimum income tax, as it is only paid if the amount that would be due thereunder is greater than the income tax otherwise payable. However, this tax was repealed on August 10, 2004 and will not be required to be paid from that date on. See note 12 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Effective March 2002, and for the term of one year, the Venezuelan government introduced a tax on certain banking transactions to be levied at a rate of 0.75%. On March 2003, the term was extended for one more year, and this tax was raised to a rate of 1.00% until June 2003, when the rate was reduced to 0.75%. The tax rate was reduced to 0.50% from December 2003 through March 2004.

In conformity with the Venezuelan tax law, taxpayers subject to income tax who carry out import, export and loan operations with related parties domiciled abroad are obliged to determine their income, costs and deductions by applying transfer pricing rules. PDVSA has obtained studies supporting its transfer pricing methodology. The resulting effects are included as a taxable item in the determination of income tax. PDVSA undertakes significant operations regulated by transfer pricing rules.

A summary of the tax effects on PDVSA’s consolidated operations for the years ended 2003, 2002 and 2001, are as follows:

	Year ended December 31
	2003	2002	2001
	($ in millions)
Income taxes	1,602	149	3,766
Production and other taxes	6,428	5,748	3,760
	8,030	5,897	7,526

For the year ended 2003, PDVSA expensed $8,030 million in taxes, compared to $5,897 million in 2002, representing an increase of 36% in the amount of taxes. Also, the effective income tax rate increased from 5.4% in 2002 to 35.1% in 2003. This increase was due principally to the inflation adjustment for tax purposes and effects of remeasurement from bolivars to dollars net of the reversal of a valuation allowance in 2003 corresponding to tax credits utilized during 2003. See note 12 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Basis of Presentation

The economic environment of our operations involves mainly the international market for crude oil and refined products. As such, the dollar is our reporting currency. See note 1(b) to our consolidated financial statements, included under “Item 18. Financial Statements.”

5.A Management’s Discussion and Analysis of Financial Condition and Results of Operations

Executive Summary

PDVSA is vertically integrated in the petroleum, gas, refining and marketing businesses. We explore and produce hydrocarbons in Venezuela and mainly, sell crude oil to the United States and Canada, the Caribbean, Europe, South America, and Asia. Also, we refine crude oil and other feedstocks in Venezuela and abroad, into a variety of products which include gasoline, diesel, fuel oil, and jet fuel, petrochemicals and industrial products, lubricants and waxes, and asphalt. Products are transported from our refineries primarily by tankers, pipeline and barge and then through terminals to our customers. These products are sold to wholesale marketers, convenience stores, airlines and to other manufacturers as feedstock.

We evaluate our operating performance of our upstream business based on the number of active rigs, production levels by field, recovery factors, the incorporation of crude oil and gas reserves, reservoirs energy levels and quantity and quality of key professionals such as petroleum engineers and geologists. Regarding our downstream business, we look at utilization rates of the refinery and petrochemical equipment, the yield of products from crude oil input and the cost of other key components such as natural gas and electricity. We evaluate our financial performance by focusing on return on capital employed and economic value added, free cash flow, operational costs per barrel of oil produced, gross margins, etc. We evaluate the performance of our specialty products such as petrochemicals and lubricants against the alternate use value of the hydrocarbons used to produce these products. In most cases, this alternate use value relates to the price of gasoline. Also we take into consideration our international and domestic markets supply percentages.

PDVSA’s financial results are a function of oil prices, supplying an optimal crude oil mix to customers and to our refineries, making profitable capital investments and using fully our refining capacity, maintaining margins on the products sold, operating our facilities in a safe way and keeping low operational costs. We assess our financial condition by means of financial ratios including interest coverage, debt coverage, debt-to-capitalization, return on capital employed, economic value added and available borrowing capacity.

PDVSA’s primary opportunities are based currently on increasing reserves of light and medium gravity crude oil, increasing the overall recovery factor, continuing the development of extra-heavy crude oil projects, and improving existing technology in order to maximize the return on our investments.

Regarding our downstream business, we are investing in increasing refining capacity, product enhancement and environmental compliance within Venezuela and abroad, expanding our markets in Latin America, the Caribbean and Asia, and improving the efficiency of our refining processes and marketing activities.

With respect to our gas business, we are actively promoting the national and international private sector participation in non-associated gas reserves and processing, enhancing our distribution processes in order to increase our domestic and international marketshares, and increasing our focus on the liquefied natural gas (LNG) markets.

With respect to petrochemicals from our refineries, we are supporting the development of new lines of business with natural gas and refining streams.

The most difficult challenges for PDVSA management in the medium term are the optimum maintenance of oil reservoirs and production facilities, investing in exploration programs to increase reserves, increasing availability of gas in western Venezuela and changes in product quality specifications. Tier II Gasoline, Ultra Low Sulfur Diesel, Group II and III Lube base oils and high performance asphalts are all being required by the market place over the next four to six years. Some of these products are being directly mandated by regulatory agencies,

others are the indirect result of regulations, but ultimately our customers will require all of these products plus possibly others not currently defined.

The challenges to being able to supply this new generation of products include: planning and executing multi-million dollar capital projects, primarily for refinery and oil and gas projects, financing these projects, and adjusting operating practices and procedures to assure reliable, high quality supplies to our customers. All this must be done without impacting our profit and efficiency improvement initiatives.

PDVSA continues to evaluate technology improvements, and believes that by increasing our implementation of high technology offshore drilling and production, 4D exploration and new quality fuels production capabilities, we will benefit from technology improvements over time.

The crude oil and refined products businesses are inherently volatile, and the primary business risk for any company engaged in the business is a sudden and radical movement in market prices. Another major risk in the oil business is operational risk, which is the risk of mechanical failure and or human error related to any operating asset. A final area of risk is political risk. In the short term, geopolitical actions could upset the supply-demand equation, affecting prices of crude oil or products and thus creating market upsets. Over the longer term, changes in laws or regulations could radically increase the cost of being in the oil business. Political risk associated with increased regulation can only be addressed on an issue specific basis. PDVSA is constantly monitoring statutory and regulatory trends which might affect the business in the countries where it operates.

Operating risk is first addressed at PDVSA by an advanced risk management system and by stringent operating practices and procedures. However, in addition to striving for operational excellence, PDVSA carries significant levels of property damage and business interruption insurance.

Political risk is an issue that must be accepted and managed, once a business has committed capital investments in a certain country. However, PDVSA’s large and diverse production, refining and distribution system provides the flexibility to react to crude and product shortages or surpluses, should they occur. For example, CITGO’s Gulf Coast refineries are complex and flexible enough to process almost any type of crude oil traded on the world market. PDVSA operates important crude oil and product storage facilities and terminals in Venezuela, Europe, the Caribbean and in various locations in the United States, in case it becomes necessary to further supplement the supply of crude oil or products. Additionally, PDVSA is reducing its political and commercial risk by diversifying its customer portfolio and by investing in refining capacity in new markets. In this regard we are evaluating business opportunities in Asia (India and China), South America (Brazil and Argentina), the Caribbean (Jamaica and Cuba) including important opportunities.

In Venezuela, PDVSA is addressing the risk of operating in an economy characterized by years of improper wealth distribution, which in turn created several accumulated economical imbalances, by contributing to the general social wellbeing through various programs designed to complement the governmental action on social issues, such as strategic food supply, education, housing, health and job creation. For such programs, PDVSA expensed approximately $546 million and $4,355 million in 2003 and 2004, respectively.

The refined products business continues to be very competitive. Industry analysts predict demand growth at 1% to 2% per year in the U.S. for the next 5 to 10 years, creating expansion opportunities for U.S. refineries, which are currently operating at near capacity throughput. While this growth trend would appear to be positive for refining and marketing companies, the industry has always exhibited strong competitive tendencies, and recent corporate consolidations have resulted in cost reduction synergies and economies of scale that translated into competitive pricing in the market place.

As noted above, the production of lower sulfurs content fuels and higher quality lubricant base stocks and asphalts is definitely a trend for the future. The high capital requirements associated with facilities equipped to produce these products may lead to further consolidation of refining capacity into the hands of financially strong companies. PDVSA will continue to monitor these trends and will take advantage of economic opportunities as they occur.

Major uncertainties for PDVSA generally coincide with market and political risks. While PDVSA cannot forecast the future of the crude oil and refined product markets and political actions, which may affect it, the Company can prepare itself for potential contingencies. PDVSA believes it is prepared to adjust to most market contingencies in ways that will not have a significant negative impact on its performance or future by maintaining adequate levels of financial liquidity and debt, by assuring that its assets distribution are flexible and by having multiple sources of supply, a diversified customer portfolio and by monitoring and analyzing the market on a continuous basis.

Even though PDVSA went through great difficulties imposed by a work stoppage-sabotage that paralyzed operations, financial systems and caused significant losses, financially, 2003 and 2004 were good years for PDVSA as a result of a positive recuperation effort, sustained production capacity, a high utilization rate of refining capacity, excellent safety performance and favorable market conditions.

As PDVSA continues to emphasize the importance of efficient operations and its commitment to safety, we will again take advantage of expected favorable market conditions in 2005. However, PDVSA operates in an industry subject to volatility in earnings. Conditions can change quickly and results may differ substantially from management’s expectations. In addition, reactions to perceived credit risks by PDVSA’s suppliers and creditors could affect the Company’s liquidity should credit lines or payment terms be restricted.

PDVSA has sufficient liquidity (defined as cash from operations, available borrowing capacity and access to accounts receivable sales facilities) to maintain its current operations, to complete capital projects that are underway and reduce its outstanding debt. Estimated capital expenditures for 2005 are approximately $5,869 million. Liquidity, defined as cash and cash equivalents, at 2003 year-end was approximately $2,938 million. PDVSA reduced its net financial debt in 2003 and 2004 in order to have less stringent covenants on its crude oil sales and in order to improve its overall financial risk management. PDVSA is not planning to issue new debt in 2005.

Results of Operations 2003 Compared to 2002

Production

Our production of crude oil and liquid petroleum gas averaged 2,595 MBPD in 2003, a 8% decrease from 2,832 MBPD produced in 2002 due basically to the work stoppage that affected PDVSA in December 2002 and the first months of 2003. By November 2002 we were producing about 3,300 MBPD and by January 2003, our production had fallen to an average of 800 MBPD. Of this total of 2,595 MBPD, 29% was light crude oil and condensates, 35% was medium crude oil, 30% was heavy and extra-heavy crude oil and the remaining 6% was liquid petroleum gas. Our production of natural gas (net of amounts re-injected) was 3,432 MMCFD in 2003 compared to 3,672 MMCFD in 2002. In 2003, our natural gas production capacity reached 7,453 MMCFD and natural gas liquid production capacity totaled 270 MBPD. Our crude oil production capacity was 3,529 MBPD in 2003 compared to 3,674 MBPD in 2002. All of our crude oil and natural gas production operations are located in Venezuela.

In 2003, the net output of refined petroleum products (including output representing our equity interest in refineries held by our affiliates in the United States and in Europe) was 2,700 MBPD, compared to 2,577 MBPD in 2002. Of this total, 1,033 MBPD (38%) were produced in our Venezuelan refineries (including the Isla Refinery in Curaçao), 1,291 MBPD (48%) was produced by the refineries in the United States, and the remaining 376 MBPD (14%), was produced by our interests in the European joint ventures.

Total Revenues

Total revenues increased $4,009 million, or 9%, from $42,580 million in 2002 to $46,589 million in 2003, due to the increase in export sales prices, partially offset by a decline in production due to the operational and administrative turmoil caused by the work stoppage.

Net Sales

Net sales increased $3,898 million, or approximately 9%, from $42,312 million in 2002 to $46,210 million in 2003. This was due mainly to an increase in average sales price of approximately 21%, from an average price per barrel of $26.56 in 2002 to $32.08 in 2003, partially offset by a 13% decrease in sales volume, from a total of 4,365 MBPD in 2002 to a total of 3,784 MBPD in 2003. See “Item 3.A Selected Financial Data” and the table captioned “PDVSA’s Consolidated Sales Volume” under “Item 4.B Business overview.”

Export Revenues of Crude Oil and Refined Products. Exports represented 57% of our sales volumes. Our exports decreased in volume by approximately 11% from 2,411 MBPD in 2002 to 2,150 MBPD in 2003, due basically to the work stoppage that affected PDVSA during the first quarter 2003. PDVSA declared a Force Majeure on its supply contracts in December 2002, which was lifted in March 2003. The average export price per barrel for Venezuelan crude oil, refined petroleum products and liquid petroleum gas was $24.89 in 2003, compared to $21.94 in 2002, representing a 13% increase.

The following table sets forth the primary markets for Venezuelan crude oil, refined petroleum products and liquid petroleum gas for 2003 and 2002.

PDVSA’s Export Sales—Geographical Breakdown

	2003	2002	Increase (Decrease)
	(MBPD, except as otherwise indicated)

United States and Canada	1,183	1,269	(7	)%
Caribbean and Central America	675	739	(9	)%
South America	204	269	(24	)%
Europe	88	134	(34	)%

We export all of the crude oil that we produce that is not processed in our Venezuelan refineries (including at the Isla Refinery in Curaçao). Of our total exports of 2,150 MBPD in 2003, 1,648 MBPD were exported (including to the Isla Refinery in Curaçao) as crude oil and 502 MBPD were exported as refined petroleum products. For the purpose of calculating export volumes, we treat crude oil processed in the Isla Refinery in Curaçao as an export of crude oil from Venezuela and do not treat the sale of refined petroleum products from the Isla Refinery as an export of refined petroleum products from Venezuela.

Sales Revenues of International Subsidiaries. In 2003, the total volumes of crude oil and refined petroleum products that we sold exceeded our total production of crude oil and liquid petroleum gas. In 2003, our total production of crude oil and liquid petroleum gas was 2,595 MBPD, compared to 3,784 MBPD of total sales of such products. PDV America, through its wholly owned subsidiaries (primarily CITGO), generates most of the sales in excess of our crude oil and liquid petroleum gas production, because it purchases crude oil and refined petroleum products from third parties (including affiliates) for supply to refining and marketing network in the United States. Total sales of refined petroleum products by PDV America were approximately 1,807 MBPD in 2003, compared to 1,658 MBPD in 2002, and its purchases of crude oil from us totaled approximately 336 MBPD in 2003, compared to 320 MBPD in 2002. PDV America’s revenues increased to $25,216 million in 2003 from $19,358 million in 2002, due to an increase in average sales price of 19% and an increase in sales volume of 9%.

Domestic Sales. In 2003, we sold 432 MBPD of refined petroleum products (including liquid petroleum gas) domestically, compared to 420 MBPD sold domestically in 2002. We also sold 302 MBPD of oil equivalent of natural gas, compared to 324 MBPD sold in 2002. Unit sales prices of refined petroleum products decreased 2%,

from $6.73 per barrel in 2002 to $6.61 per barrel in 2003, and unit sales prices of natural gas decreased from $0.71 per MCF, or $4.34 per BOE, in 2002 to $0.61 per MCF, or $3.20 per BOE, in 2003. Between December 2002 and March 2003 PDVSA imported and sold 14.5 million barrels of gasoline and diesel in Venezuela due to the shut down of our local refineries affected by the work stoppage.

Petrochemical and Other Sales. Our net sales for 2003 included $1,071 million from sales of petrochemicals, bitumen and coal, a 11% decrease compared to $1,201 million of revenues from sales of these products in 2002. This decrease in net sales is due primarily to a 34% decrease in volumes produced, as a consequence of lower feeedstock supply from PDVSA, which in turn was unable to deliver due to the 2003 work stoppage.

Equity in Earnings of Non-consolidated Investees

Equity in earnings of non-consolidated investees increased 41% to $379 million in 2003 from $268 million in 2002. This resulted primarily due to higher earnings reported by the affiliates Hovensa, Petrozuata and Chalmette.

Purchase of Crude Oil and Products

Our purchase of crude oil and products increased by 17% from $17,956 million in 2002 to $21,016 million in 2003, primarily due to an increase of purchases from third parties as a consequence of the reduction in transfers from PDVSA Petroleo. We also purchased an average of 55 MBPD and 61 MBPD of refined products and crude oil for our Venezuelan operations, during 2003 and 2002, respectively. Other purchases of crude oil were made to meet our supply commitments. Through CITGO, we purchase crude oil and refined petroleum products from third parties (including affiliates) to supply our refining and marketing networks in the United States. As previously discussed, we imported 14.5 million barrels of gasoline and diesel at a cost of around $640 million to supply local market during the work stoppage that affected our refineries during the first quarter of 2003.

Operating Expenses

Our operating expenses increased slightly by $39 million or less than 1%, from $9,299 million in 2002 to $9,338 million in 2003 due to an increase in refining costs for our subsidiary CITGO.

Total refining costs represented 42% and 39% of our total operating expenses for 2003 and 2002, respectively. Costs incurred at our Venezuelan refineries (including the Isla Refinery) represented 8% of our total operating expenses in 2003 and 9% of our total operating expenses in 2002.

Exploration Expenses

Our total exploration expenses were $27 million in 2003, compared to $133 million in 2002. The decrease in exploration expenses is attributable to a decrease in exploratory activities, particularly with respect to acquisition of 2D and 3D seismic lines. Nevertheless, we added 162 MMB of proved crude oil reserves from newly discovered reserves in 2003 compared to 135 MMB from newly discovered reserves in 2002. We conducted exploratory drilling of seven wells in 2003, compared to ten wells in 2002.

Depreciation and Depletion

Depreciation and depletion decreased 7% from $3,038 million in 2002 to $2,824 million in 2003. This decrease is explained by the fact that most of our assets are subject to the units-of-production depreciation method, which is affected by the production level of each year. In 2003 the production level was lower than in 2002. Additionally, the increase in provisions related to assets caused a decrease in the base of the assets depreciable costs.

Asset Impairment

Asset impairment decreased by $426 million from $722 million in 2002 to $296 million in 2003, principally because of the results of the asset impairment study of December 2003, which determined that it was necessary to increase the provision for the impairment of certain assets of the south west production division. For the rest of the assets, it was not necessary to change the December 31, 2002 provision.

Selling, Administrative and General Expenses

Selling, administrative and general expenses decreased $375 million or 20% from $1,854 million in 2002 to $1,479 million in 2003, due principally to a reduction of approximately $170 million in labor costs and a decrease of $126 million in pension plans, both of which were caused by the termination of a large number of employees.

Financing Expenses

Financing expenses decreased by 18% to $627 million in 2003 from $763 million in 2002, in each case, net of capitalized interest of $40 million and $51 million, respectively. The decrease in financing expenses resulted primarily from the decrease in the weighted average variable interest rate from 5.40% in 2002 to 2.94% in 2003 and an a decrease in average indebtedness outstanding from $8,335 million in 2002 to $7,629 million in 2003, offset by an increase in the weighted average fixed interest rate from 7.97% in 2002 to 8.25% in 2003.

Results of Operations 2002 Compared to 2001

Production

Our production of crude oil and liquid petroleum gas averaged 2,832 MBPD in 2002, a 13% decrease from 3,267 MBPD produced in 2001. Of this total, 29% was light crude oil and condensates, 34% was medium crude oil, 31% was heavy and extra-heavy crude oil and the remaining 6% was liquid petroleum gas. Our production of natural gas (net of amounts re-injected) was 3,672 MMCFD in 2002 compared to 4,093 MMCFD in 2001. In 2002, our natural gas production capacity reached 7,560 MMCFD and natural gas liquid production capacity totaled 288 MBPD. Our crude oil production capacity was 3,653 MBPD in 2002 compared to 3,990 MBPD in 2001. All of our crude oil and natural gas production operations are located in Venezuela.

In 2002, the net output of refined petroleum products (including output representing our equity interest in refineries held by our affiliates in the United States and in Europe) was 2,577 MBPD, compared to 2,863 MBPD in 2001. Of this total, 1,182 MBPD (46%) was produced in our Venezuelan refineries (including the Isla Refinery in Curaçao), 1,124 MBPD (43%) was produced by the refineries in the United States, and the remaining 271 MBPD (11%), was produced by our interests in the European joint ventures.

Total Revenues

Total revenues decreased $3,670 million, or 8%, from $46,250 million in 2001 to $42,580 million in 2002.

Net Sales

Net sales decreased $3,474 million, or approximately 8%, from $45,786 million in 2001 to $42,312 million in 2002. This was due mainly to a 3% decrease in sales volume, from a total of 4,478 MBPD in 2001 to a total of 4,365 MBPD in 2002, and a decrease in average sales price of approximately 6%, from an average price per barrel of $28.21 in 2001 to $26.56 in 2002. See “Item 3.A Selected financial data” and the table captioned “PDVSA’s Consolidated Sales Volume” under “Item 4.B Business overview.”

Export Revenues of Crude Oil and Refined Products. Exports represented 55% of our sales volumes. Our exports decreased in volume by approximately 13% from 2,762 MBPD in 2001 to 2,411 MBPD in 2002. The average export price per barrel for Venezuelan crude oil, refined petroleum products and liquid petroleum gas was $21.94 in 2002, compared to $20.21 in 2001, representing a 9% increase.

The following table sets forth the primary markets for Venezuelan crude oil, refined petroleum products and liquid petroleum gas for 2002 and 2001.

PDVSA’s Export Sales—Geographical Breakdown

	2002	2001	Increase (Decrease)
	(MBPD, except as otherwise indicated)

United States and Canada	1,269	1,497	(15	)%
Caribbean and Central America	739	793	(7	)%
South America	269	321	(16	)%
Europe	134	151	(11	)%

We export all of the crude oil that we produce that is not processed in our Venezuelan refineries (including to the Isla Refinery in Curaçao). Of our total exports of 2,411 MBPD in 2002, 1,764 MBPD were exported (including to the Isla Refinery in Curaçao) as crude oil and 647 MBPD were exported as refined petroleum products. For the purpose of calculating export volumes, we treat crude oil processed in the Isla Refinery in Curaçao as an export of crude oil from Venezuela and do not treat the sale of refined petroleum products from the Isla Refinery as an export of refined petroleum products from Venezuela.

Sales Revenues of International Subsidiaries. In 2002, the total volumes of crude oil and refined petroleum products that we sold exceeded our total production of crude oil and liquid petroleum gas. In 2002, our total production of crude oil and liquid petroleum gas was 2,832 MBPD, compared to 4,365 MBPD of total sales of such products. PDV America, through its wholly owned subsidiaries (primarily CITGO), generates most of the sales in excess of our crude oil and liquid petroleum gas production, because it purchases crude oil and refined petroleum products from third parties (including affiliates) for supply to refining and marketing network in the United States. Total sales of refined petroleum products by PDV America were approximately 1,658 MBPD in 2002, compared to 1,610 MBPD in 2001, and its purchases of crude oil from us totaled approximately 320 MBPD in 2002, compared to 348 MBPD in 2001. PDV America’s revenues decreased to $19,358 million in 2002 from $19,601 million in 2001, due to a decrease in average sales price of 4%, offset by an increase in sales volume of 3%.

Domestic Sales. In 2002, we sold 420 MBPD of refined petroleum products (including liquid petroleum gas) domestically, compared to 458 MBPD sold domestically in 2001. We also sold 324 MBPD of oil equivalent of natural gas, compared to 307 MBPD sold in 2001. Unit sales prices of refined petroleum products decreased 23%, from $8.74 per barrel in 2001 to $6.73 per barrel in 2002, and unit sales prices of natural gas decreased from $0.88 per MCF, or $5.35 per BOE, in 2001 to $0.71 per MCF, or $4.34 per BOE, in 2002.

Petrochemical and Other Sales. Our net sales for 2002 included $1,201 million from sales of petrochemicals, bitumen and coal, a 14% decrease compared to $1,403 million of revenues from sales of these products in 2001. This decrease in net sales is due primarily to the effects of devaluation on petrochemical revenues denominated in bolivars.

Equity in Earnings of Non-consolidated Investees

Equity in earnings of non-consolidated investees decreased 42% to $268 million in 2002 from $464 million in 2001. This resulted primarily from the 84% decrease in PDV Holding’s equity in earnings from $225 million in 2001 to $36 million in 2002, which was due to the $113 million decrease in our share in the earnings of Chalmette Refining from a $50 million gain in 2001 to a $(63) million loss in 2002. Additionally, our share in the earnings of Merey Sweeny decreased $68 million, from a $66 million gain in 2001 to a $(2) million loss in 2002. Finally, in 2002, PDV Holding experienced a $12 million reduction in its earnings from other investments. This decrease in earnings was partially offset by a $4 million increase of LYONDELL-CITGO’s earnings from $74 million in 2001 to $78 million in 2002.

Purchase of Crude Oil and Products

Our purchase of crude oil and products decreased by 1% from $18,228 million in 2001 to $17,956 million in 2002, primarily due to a decrease in volumes. We also purchased an average of 61 MBPD and 55 MBPD of refined products and crude oil for our Venezuelan operations, during 2002 and 2001, respectively. Other purchases of crude oil were made to meet our supply commitments. Through CITGO, we purchase crude oil and refined petroleum products from third parties (including affiliates) to supply our refining and marketing networks in the United States.

Operating Expenses

Our operating expenses decreased by $1,583 million, or 15%, from $10,882 million in 2001 to $9,299 million in 2002, due to lower oil production in 2002.

Total refining costs represented 39% and 36% of our total operating expenses for 2002 and 2001, respectively. Costs incurred at our Venezuelan refineries (including the Isla Refinery) represented 9% of our total operating expenses in 2002 and 10% of our total operating expenses in 2001.

Exploration Expenses

Our total exploration expenses were $133 million in 2002, compared to $174 million in 2001. The decrease in exploration expenses is attributable to our abandonment of two dry wells in 2002 (thereby reducing our exploration expenses by $25 million in 2002, compared to $9 million in 2001) and a decrease in exploratory drilling costs. We conducted exploratory drilling of 10 wells in 2002, compared to 11 wells in 2001, principally attributable to our joint ventures and association agreements in connection with our Orinoco Belt projects.

Depreciation and Depletion

Depreciation and depletion increased 16% from $2,624 million in 2001 to $3,038 million in 2002, due to an increase in our property, plant and equipment resulting from the capitalization of new assets at the end of 2001, principally attributable to our joint ventures and association agreements in connection with our Orinoco Belt projects.

Asset Impairment

Asset impairment increased by $465 from $257 in 2001 to $722 in 2002, principally due to an increase in oil and gas wells included under oil and gas production assets, which PDVSA plans to retire.

Selling, Administrative and General Expenses

Selling, administrative and general expenses remained at a similar level of $1,854 million in 2002 and $1,853 million in 2001.

Financing Expenses

Financing expenses increased by 50% to $763 million in 2002 from $509 million in 2001, in each case, net of capitalized interest of $7 million and $51 million, respectively. The increase in financing expenses resulted primarily from the increase in the weighted average variable interest rate from 4.73% in 2001 to 5.40% in 2002 and an increase in average indebtedness outstanding from $8,013 million in 2001 to $8,335 million in 2002, offset by a decrease in the weighted average fixed interest rate from 8.13% in 2001 to 7.97% in 2002.

5.B Liquidity and Capital Resources

Our liquidity needs are attributable to our exploration and development of hydrocarbon reserves, our production, processing and refining activities and our maintenance of machinery and equipment, each of which

require substantial capital investments. We must continue to invest capital to maintain or to increase the number of hydrocarbon reserves that we operate and the amount of crude oil that we produce and process. We generally rely on funds provided by our operations to meet these needs. We expect to meet our capital expenditure requirements primarily through cash flows generated from our operations. We have borrowings under our loan agreements and credit facilities and, from time to time, we also may pursue financing alternatives in the international capital markets. In our opinion, we have sufficient working capital for our present requirements.

Cash Flows from Operating Activities

For the year ended December 31, 2003, PDVSA’s net cash provided by operating activities totaled $5,746 million, primarily reflecting $2,720 million of net income, $2,824 million of depreciation and depletion, $296 million of asset impairment, $240 million dividends received from non-consolidated investess, less equity in earnings of non-consolidated investees of $379 million, less $244 million of payments for employee termination, pension and other postretirement benefits, less $53 million of deferred income taxes and changes in working capital of $342 million.

The more significant changes in working capital were an increase in accounts receivable of approximately $1,691 million due to the increase in prices of crude oil and refined products and an increase in taxes payable, accrued and other liabilities of $1,135 million, partially offset by a decrease in prepaid expenses and other assets of $892 million.

Cash Flows from Investing Activities

Net cash used in investing activities totaled $902 million for 2003, resulting from $1,969 million of capital expenditures, less net movements on restricted cash of $1,146, which includes principally transfers to the FEM fund, partially offset by the creation of a trust in the Social and Economic Development Bank of Venezuela and reductions in the fund for the Orinoco Belt joint ventures.

For the three-year period ended December 31, 2003, our capital expenditures were as follows:

	2003		2002		2001
	($ in millions)
In Venezuela:
Exploration and Production	1,364		$	1,556	$	507
Refining	160		365		2,809
Petrochemicals and others	102		83		208
	$	1,626	$	2,004	$	3,524
Foreign-Refining	343		739		257
	$	1,969	$	2,743	$	3,781

The following table sets forth our planned capital expenditures by geographic locations for the period 2005-2007:

	2004	2005	2006	2007	2008
Venezuela	2,990	5,869	7,669	10,195	7,478
United States	341	515	406	475	475
Europe and Caribbean	154	223	203	203	203
	3.485	6,607	8,278	10,873	8,156

Our capital expenditures in Venezuela for 2004 were as follows: $2,096 million for exploration and production, $298 million for refining and marketing, $443 million for natural gas projects, $89 million for petrochemicals and others and $64 million for equity investments in our Orinoco Belt associations. Our planned capital expenditures for 2005 in Venezuela are as follows: $3,663 million for exploration and production, $412 million for refining and marketing, $973 million for natural gas projects, $12 million for petrochemicals and others

and $809 million for equity investments in our Orinoco Belt. The capital expenditures for our international subsidiaries and affiliates are principally to comply with increasingly stringent environmental laws affecting their operations. The original 2005 capital expenditure budget for Venezuela of $5,971 million has been revised to $5,869 million.

The FIEM and the FEM

In October 2001 and 2002, and January and April 2003, the Venezuelan government introduced reforms to the FIEM Law and, among other changes, suspended the contributions for the last quarter of 2001 and the years 2002 and 2003. In June 2002, the board of directors of the FIEM and the National Assembly authorized PDVSA to withdraw up to $2,445 million. During 2003, the National Government and the National Assembly (Congress) authorized PDVSA to withdraw $1,430 million from the funds deposited in the FIEM. As of December 31, 2003, these funds have been utilized completely by PDVSA.

In November 2003, the Venezuelan Government established the FEM (formerly the FIEM) to help stabilize national, state and municipal expenses resulting from fluctuations in ordinary income. Through the BCV, the National Government transferred the balance available of $698 million from the FIEM to the FEM. FEM is funded by the government, state and municipal entities and PDVSA. FEM may receive additional funding from the privatization of public companies, concessions, and strategic associations, if such funds have not been used to pay public liabilities. PDVSA is required to make contributions to the FEM equivalent to fifty percent (50%) of the difference between the income from its oil and by-products exports (in US dollars) and the average of such income collected during the last three calendar years, after deducting the taxes caused in relation to such income.

The deposits made to the FEM may be used in the event of a decrease in the fiscal income provided by petroleum, a decrease in the income provided by the oil and by-products exports as compared to the average of such income collected during the last three calendar years, or in the event of a national state of emergency. In the event that funds from the FEM become available, PDVSA will be able to withdraw an amount that will not exceed seventy-five percent (75%) of the difference between the estimated income for that period and the average of such income collected during the last three calendar years, upon the approval of the Board of Directors of the FEM and the opinion of the Permanent Finance Commission of the National Assembly. Likewise, a maximum resources accrual level is established for PDVSA consisting of 30% of the average oil exports during the last three years. Any excess fund will be transferred to the Fondo de Ahorro Intergeneracional. However, if PDVSA is required to execute special investment plans for the management and expansion of its operations, it may use part of such excess, upon the approval of the Stockholder’s Assembly.

In December 2004, the FEM had total funds of $705 million, including $7 million of accrued interest. See note 4 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Cash Flows from Financing Activities

Consolidated net cash used in financing activities totaled approximately $3,609 million, resulting primarily from payments of dividends in the amount of $2,326 million, debt repayments of $2,245 million and $962 million for issuance of debt.

As of December 31, 2003, PDVSA had an aggregate of $7,015 million of indebtedness outstanding that mature on various dates through 2033. PDVSA and its subsidiaries also have the following credit facilities available at December 31, 2003:

Source of Financing		($ in millions)
Loan agreements - secured		163
Lines of credit - secured		39
Lines of credit - unsecured		260
		462

In 2002, we paid dividends of $2,652 million and we declared $2,752 million in dividends. In 2003, we declared $2,594 million in dividends and paid $2,326 million. See note 15 to our consolidated financial statements, included under “Item 18. Financial Statements.”

On February 27, 2003, CITGO issued $550 million aggregate principal amount of 11³/₈ % unsecured senior notes due February 1, 2011. In connection with this debt issuance, CITGO repurchased $50 million principal amount of its 7¹/₈ % senior notes due 2006. On July 25, 2003, CITGO made a $500 million dividend payment for the purpose of enabling its parent, PDV America, to make the principal repayment of $500 million, 7⁷/₈ % senior notes due August 1, 2003. On October 22, 2004, CITGO issued $250 million of 6% unsecured senior notes due October 15, 2011. In connection with this transaction, CITGO redeemed approximately $540 million principal amount of its 11³/₈ % senior notes due 2011.

In January 2003, CITGO’s debt rating was lowered which caused a termination event under CITGO’s accounts receivable sale facility existing at that time, which ultimately led to the repurchase of $125 million of accounts receivable and cancellation of the facility on January 31, 2003. That facility had a maximum size of $225 million, of which $125 million was used at the time of cancellation. On February 28, 2003 a new accounts receivable facility of $200 million was established. This facility allows for the non-recourse sale of certain accounts receivable to independent third parties. On August 1, 2003, $200 million was sold under this facility.

On February 27, 2003, CITGO closed on a three-year $200 million senior secured term loan with a variable interest rate, which was retired on June 25, 2004.

On May 23, 2003, CITGO issued $39 million of tax-exempt environmental revenue bonds due 2031. The proceeds from these bonds are being used for qualified projects at the Corpus Christi refinery.

On May 3, 2004, CITGO issued $25 million of tax-exempt environmental revenue bonds due 2032 through a governmental issuer that refunded $25 million of taxable environmental revenue bonds due 2028 previously issued through that issuer. The tax-exempt bonds are supported by a letter of credit issued by a bank.

On August 2, 2004 PDVSA’s subsidiary PDVSA Finance completed its tender offer and consent solicitation for its outstanding notes. Holders of an aggregate of 96.34% of the $2.6 billion in principal amount of the notes, tendered and delivered their consent pursuant to the tender offer and to an amendment to certain provisions of the Senior Indenture. The total of the notes repurchased was $2,511,822,144. This transaction provided PDVSA with more capital flexibility in order to finance its Business Plan. The results of the tender offer and the consent solicitation were as follows:

Notes	CUSIP/ISIN No	Outstanding Principal Amount before Tender Offer			Principal Amount Validly Tendered			Outstanding Principal Amount after Tender Offer
6.250% Euro Notes due 2006	Xs0096444749	€		88,400,000	€		87,449,258	€		950,742
6.650% Notes due 2006	693300AE5 / US693300AE52	$	300,000,000		$	291,693,000		$	8,307,000
9.375% Notes due 2007	693300AP0/ US693300AP00 G6954PAJ9/ USG6954PAJ96	$	250,000,000		$	243,980,000		$	6,020,000
6.800% Notes Due 2008	693300AF2 / US693300AF28 693300AC9 / US693300AC96 G6954PAC4 / USG6954PAC44	$	300,000,000		$	293,859,000		$	6,141,000
9.750% Notes Due 2010	693300AR6 / US693300AR65 G6954PAK6 / USG6954PAK69	$	250,000,000		$	225,810,000		$	24,190,000
8.500% Notes Due 2012	693300AU9 / US693300AU94	$	500,000,000		$	471,133,000		$	28,867,000
7.400% Notes Due 2016	693300AJ4 / US693300AJ40	$	400,000,000		$	387,335,000		$	12,665,000
9.950% Notes Due 2020	693300AT2 / US693300AT22 693300AS4 / US693300AS49	$	100,000,000		$	97,050,000		$	2,950,000
7.500% Notes Due 2028	693300AK1 / US693300AK13	$	400,000,000		$	394,790,000		$	5,210,000

Total outstanding principal amount of notes: $2,607,326,440
Total principal amount of notes validly tendered: $2,511,822,144
Percentage of notes validly tendered, considered as a single class: 96.34%

In conjunction with the repurchase of the notes, a premium and expenses totaling US$71.6 million was charged to the 2004 results of operations.

We currently have long-term debt ratings assigned by certain internationally recognized credit rating agencies as follows:

	CITGO	PDVSA Finance
	(unsecured)	(unsecured)

Moody’s Investors Service	Ba2	B1
Standard & Poor’s Ratings Services	BB	B+
Fitch Ratings	BB	BB

During 2003, PDVSA through CVP and as part of the process to support the social projects carried out by the National Government, donated to Venezuela $251 million in non-cash materials purchased from the counterparty to the energy cooperation and integration agreement described below. This donation was expended during 2003 and is included in costs and expenses. The debt created by CVP’s purchases from this counterparty was later paid through an offset of trade accounts receivable due from an affiliate of the counterparty. The trade accounts receivable that were offset were generated by sales made in connection with the Caracas energy cooperation and integration agreement, Convenio de Cooperación y de Integración Energética de Caracas,” that had been transferred from PDVSA Petróleo to CVP. See notes 18 and 22(a) to our consolidated financial statements, included under “Item 18. Financial Statements.”

As part of the support for diverse programs established by the National Government during 2003, PDVSA has made contributions for donations and to several social programs for $22 million and $227 million, respectively, that are included as costs and expenses in the statement of income. See note 18 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Contractual Obligations and Commercial Commitments

Most of our export sales of crude oil to third parties, including customers in the United States with which we maintain long-standing commercial relationships, are made at market prices pursuant to our general terms and conditions, and priced in dollars. Among our customers are major oil companies and other medium-sized companies. Although our general terms and conditions do not require specified volumes to be bought or sold, historically, a majority of our customers have taken shipments on a regular basis at a relatively constant volume throughout the year.

The following table summarizes future payments for PDVSA’s contractual obligations at December 31, 2003.

Future Payments for PDVSA’s Contractual Obligations
December 31, 2003

($ in millions)

	Total	less than 1 year	1-3 years	3-5 years	more than 5 years
Long-term debt	7,015	749	1,600	1,370	3,296
Capital lease obligations	60	25	12	12	11
Operating leases	1,508	311	515	448	234
Estimated crude purchase obligations (1)	12,342	2,057	4,114	4,114	2,057
Estimated product purchase obligations	22,838	5,182	8,820	8,836	(*)
Other commitments	4,396	715	1,176	989	1,516
Total Contractual Cash Obligations	48,159	9,039	16,237	15,769	7,114

(1) Obligations for Ruhr Oel

(*) PDVSA, through CITGO, intends to continue purchasing a portion of its refined product supply from related parties.

We also have various agreements for supplies with various companies, which are summarized as follows (thousands of barrels a day):

Company	Delivery obligation	Year of termination

Ruhr Oel	237	2022
Nynäs Petroleum	57	2005
LYONDELL-CITGO	230	2017
Chalmette Refining	90	Duration of the strategic association period
ConocoPhillips	172	2020
Hovensa	270	Between 2008 and 2022
	1,056

Critical Accounting Policies

The preparation of financial statements in conformity with Accounting Principles Generally Accepted in the United States of America requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the reported amounts of assets and liabilities. Actual outcomes could differ from the estimates and assumptions used. The following areas are those that management believes are important to the financial statements and which require significant judgment and estimation because of inherent uncertainty.

Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed

A reduction in our crude oil production or export activities or a decline in the prices of crude oil and refined petroleum products for a substantial period of time may materially and adversely affect our operations, cash flow, and financial results. We review for impairment long-lived assets and certain identifiable intangibles, to be held and used, whenever events indicate that the carrying amount of an asset may not be recoverable.

Our review of impairment of an asset is based on a comparison of the carrying amount of an asset to future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flow an impairment charge is required for the amount by which the carrying of the asset exceeds the fair value of the asset.

Environmental Expenditures

The costs to comply with environmental regulations are significant. Environmental expenditures that relate to current or future revenues are expensed or capitalized as appropriate. Expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. We constantly monitor our compliance with environmental regulations and respond promptly to issues raised by regulatory agencies. Liabilities are recorded when environmental assessments and/or cleanups are probable and the costs can be reasonably estimated. Environmental liabilities are not discounted to their present value. Subsequent adjustments to estimates, to the extent required, may be made as more refined information becomes available.

Litigation

PDVSA and its subsidiaries and joint ventures are involved in various lawsuits and claims arising in the normal course of their businesses. External and internal legal counsel continually review the status of these lawsuits and claims. These reviews provide the basis for which we determine whether or not to record accruals for potential losses. Accruals for losses are recorded when, in management’s opinion, such losses are probable and reasonably estimable. If known lawsuits and claims were to be determined in a manner adverse to PDVSA, and in amounts greater than our accruals, then such determinations could have a material adverse effect on our results of operations in a given reporting period.

Oil and Gas Reserves

All the crude oil and natural gas reserves located in Venezuela are owned by Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and reviewed by the Ministry of Energy and Petroleum, using reserve criteria which are consistent with those prescribed by the American Petroleum Institute (API) and the U.S. Securities and Exchange Commission. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Accordingly, these estimates do not include probable or possible reserves. Our estimates of reserves are not precise and are subject to revision. We review these crude oil and natural gas reserves annually to take into account, among other things, production levels, field reviews, the addition of new reserves from discoveries, year-end prices and economic and other factors. Proved reserve estimates may be materially different from the quantities of crude oil and natural gas that are ultimately recovered.

Recently Issued Accounting Standards

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. The Company applies FIN 46R to variable interests in VIEs created after December 31, 2003. For variable interests in VIEs created before January 1, 2004, the Interpretation will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. The Company expects that the adoption of FIN 46R will not have a material impact on its consolidated financial position or results of operations.

In April 2003, the FASB issued SFAS No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”. The changes in SFAS No. 149 improve financial reporting by requiring that contracts with comparable characteristics be accounted for similarly. Those changes will result in more consistent reporting of contracts as either derivatives or hybrid instruments. SFAS No. 149 is effective for contracts entered into or modified after June 30, 2003, except for certain issues from SFAS No. 133 which have been effective for fiscal quarters that began prior to June 15, 2003 and for hedging relationships designated after June 30, 2003. In addition, all provisions of SFAS No. 149 should be applied prospectively. The adoption of SFAS No. 149 did not have a material effect on PDVSA’s consolidated financial position or results of operations.

The FASB’s Emerging Issues Task Force Abstract No. 01-8, “Determining Whether an Arrangement Contains a Lease” (“EITF 01-8”) issued in May 2003, requires that when PDVSA makes an evaluation of whether an arrangement contains a lease within the scope of SFAS No. 13, “Accounting for Leases”, such an assessment should be based on the substance of the arrangement and should be made at inception of the arrangement based on all of the facts and circumstances. A reassessment of an arrangement should be based on the facts and circumstances as of the date of reassessment, including the remaining term of the arrangement. The consensus in EITF 01-8 should be applied to (a) arrangements agreed to or committed to, if earlier, after the beginning of an entity’s next reporting period beginning after May 28, 2003, (b) arrangements modified after the beginning of an

entity’s next reporting period beginning after May 28, 2003, and (c) arrangements acquired in business combinations initiated after the beginning of an entity’s next reporting period beginning after May 28, 2003. The Company is in the process of evaluating the effects, if any, of this standard on its consolidated financial position and results of operations.

In December 2003, the FASB issued SFAS No. 132R (revised 2003), “Employers’ Disclosures about Pensions and Other Postretirement Benefits”. It does not change the measurement or recognition of those plans. The Statement retains and revises the disclosure requirements contained in the original FASB Statement No. 132 “Employers’ Disclosures about Pensions and Other Postretirement Benefits”, which it replaces. It requires additional disclosures to those in the original Statement No. 132 about assets, obligations, cash flows and net periodic benefit cost of defined benefit pension plans and other defined benefit postretirement plans.

In March 2004, the EITF reached a consensus on Issue 03-01, The Meaning of Other-Than-Temporary Impairment and Its Application to Certain Investments (EITF 03-01). EITF 03-01 provides a step model to determine whether an investment, within the scope of the EITF Issue, is impaired and if an impairment is other-than-temporary. In addition, it requires that investors provide certain disclosures for cost method investments and, if applicable, other information related specifically to cost method investments. The EITF 03-01 impairment model shall be applied prospectively to all current and future affected investments, effective in reporting periods beginning after June 15, 2004. The disclosure requirements are effective for annual periods for fiscal years ending after June 15, 2004. PDVSA is in the process of analyzing the effects of this statement.

In April 2004, the FASB issued FASB Staff Position No. 141-1 and No. 142-2, “Interaction of FASB Statements No. 141, Business Combinations, and No. 142, Goodwill and Other Intangible Assets, and EITF Issue No. 04-2, “Whether Mineral Rights Are Tangible or Intangible Assets.” (“FSP FAS 141-1 and FAS 142-2”). This FSP amends statements 141 and 142 to address the inconsistency between the consensus on EITF issue 04-02, that mineral rights are tangible assets and the characterization of mineral rights as intangible assets in statements 141 and 142. The guidance in this FSP should be applied to the first reporting period beginning after April 29, 2004.

In September 2004, the FASB issued FASB Staff Position EITF 03-1-1 “Effective Date of Paragraphs 10-20 of EITF Issue No. 03-1” (FSP EITF 03-1-1). FSP EITF 03-1-1 delays the effective date for the measurement and recognition guidance contained in paragraphs 10-20 of EITF 03-1. The disclosure requirements of EITF 03-1 remain effective for fiscal years ending after June 15, 2004. No effective date for the measurement and recognition guidance has been established in FSP EITF 03-1-1. During the period of delay, FSP EITF 03-1-1 states that companies should continue to apply current guidance to determine if an impairment is other-than-temporary.

In September 2004, the FASB’s Emerging Issues Task Force issued EITF Abstract 03-13 “Applying the Conditions in Paragraph 42 of FASB Statement No. 144, Accounting for the impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations” (EITF 03-13) to provide guidance on applying SFAS 144, “Determining Whether to Report Discontinued Operations.” SFAS 144 discusses when an entity should disclose a “component” as discontinued operations. Under SFAS 144, a component should be disclosed as discontinued operations when continuing cash flows are eliminated and when there is no significant continuing involvement with the component. EITF 03-13 provides additional guidance on factors to consider in evaluating what constitutes continuing cash flows and continuing significant influence. This Statement is effective for fiscal periods beginning after December 15, 2004.

In September 2004, the FASB issued FASB Staff Position No. 142-2, “Application of FASB Statement No.142, Goodwill and Other Intangible Assets, to Oil-and Gas-Producing Entities” (“FSP FAS 142-2”). FSP FAS 142-2 believes that the scope exception of FASB Statement No 142 includes the balance sheet classification and disclosures for drilling and mineral rights of oil-and gas-producing entities that are within the scope of FASB Statement No. 19, Financial Accounting and Reporting by Oil-and Gas-Producing Companies. The guidance in this FSP shall be applied to the first reporting period beginning after September 2004.

evaluated to determine if a settlement of a preexisting relationship exists, and the accounting for the preexisting relationship. PDVSA is in the process of analyzing the effects of this statement.

In December 2004, the FASB issued FASB Staff Position No. 109-1, “Application of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified Production Activities Provided by the American Jobs Creation Act of 2004” (“FSP FAS 109-1”). The American Jobs Creation Act introduces a special 9% tax deduction on qualified production activities. FSP FAS 109-1 clarifies that this tax deduction should be accounted for as a special tax deduction in accordance with FASB Statement No. 109. This FSP is effective upon issuance. The Company does not expect the adoption of this new tax provision to have a material impact on its consolidated financial position, results of operations or cash flows.

In December 2004, the FASB issued FASB Staff Position No. 109-2, “Accounting and Disclosure Guidance for the Foreign Earnings Repatriation Provision within the American Jobs Creation Act of 2004” (“FSP FAS 109-2”). The American Jobs Creation Act introduces a special one-time dividends received deduction on the repatriation of certain foreign earnings to a U.S. taxpayer (repatriation provision), provided certain criteria are met. FSP FAS 109-1 believes an enterprise is allowed time beyond the financial reporting period of enactment to evaluate the effect of the “repatriation provision” on the plan for reinvestment or repatriation of foreign earnings for purposes of applying FASB Statement No. 109. This FSP is effective upon issuance.

In December 2004, the FASB issued SFAS No. 151, “Inventory Costs, an Amendment of ARB No. 43, Chapter 4”. SFAS No. 151 amends the guidance in Accounting Research Bulletin (ARB) No. 43, Chapter 4, “Inventory Pricing”, to clarify the accounting for abnormal amounts of idle facility expense, freight, handling costs and spoilage. In addition, SFAS No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. SFAS No. 151 will be effective for inventory cost incurred on or after January 1, 2006.

In December 2004, the FASB issued SFAS No. 153, “Exchanges of Nonmonetary Assets - An Amendment of APB Opinion No. 29”. SFAS No. 153 eliminates an exception in APB No. 29 for non-monetary exchanges of similar productive assets and replaces it with a general exception for exchanges of non-monetary assets that do not have commercial substance. SFAS No. 153 will be effective for non-monetary asset exchanges occurring on or after January 1, 2006.

In March 2005, the FASB issued Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations” (“FIN 47”), which clarifies the application of FASB Statement No. 143, “Accounting for Asset Retirement Obligations” (“SFAS No. 143”). FIN 47 clarifies (i) that an entity is required to recognize a liability for the fair value of a conditional asset retirement obligation when incurred if the liability’s fair value can be reasonably estimated; and (ii) when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application for interim financial information is permitted but is not required.

In April 2005, the FASB issued FASB Staff Position No. 19-1, “Accounting for Suspend Well Costs” (“FSP FAS 19-1”). FSP FAS 19-1 believes that the exploratory well costs should continue to be capitalized when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the enterprise is making sufficient progress assessing the reserves and the economic operating viability of the project. The guidance in this FSP shall be applied to the first reporting period beginning after April 2005.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections” replacement of APB Opinion No. 20 and FASB Statement No. 3. Early adoption is permitted for accounting changes and corrections of errors made in fiscal years beginning after the date this Statement is issued. This Statement does not change the transition provisions of any existing accounting pronouncements, including those that are in a transition phase as of the effective date of this Statement. This Statement shall be effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005.

5.C Research and development, patents and licenses

As of December 31, 2003, the amounts that we have spent on our research and development activities have not been material. See “Item 4.B Business overview – Research and Development” and note 1(o) to our consolidated financial statements, included under “Item 18. Financial Statements.”

Item 6. Directors, Senior Management and Employees

6.A Directors and senior management

In accordance with our charter, we are managed by our board of directors and our president. Our board of directors is responsible for convening our shareholder’s meetings, preparing our year-end accounts and presenting them at our shareholder’s meetings and reviewing and monitoring our economic, financial and technical strategies.

Our board of directors comprises eleven members: a president, two vice presidents, five internal directors and three external directors. Our board of directors is directly appointed by the President of Venezuela for an initial term of two years, which may be extended indefinitely until a new board of directors is appointed. Our board of directors meets weekly and, at other times, when summoned by the President of PDVSA.

Pursuant to our charter, the President of PDVSA has broad powers to act on behalf of PDVSA and to represent PDVSA in its dealings with third parties, subject only to those powers expressly reserved to the board of directors or reserved to be effected at our general shareholder’s meeting. The President of PDVSA determines and is responsible for the implementation of the goals, strategies and budgets (which must be approved at the general shareholder’s meeting) for our different businesses. Such goals, strategies and budgets are reviewed and monitored by our board of directors.

In January 2005, the Venezuelan government appointed a new board of directors for PDVSA comprised of the President, two Vice-Presidents, five internal directors and three external directors. These directors will serve until 2007, and that two-year term may be extended indefinitely until a new board of directors is appointed. Our current directors and executive officers are:

Name	Age	Position with PDVSA	Date of Appointment
Rafael Ramírez Carreño	42	President	2005
Luis Vierma	51	Vice-President	2005
Alejandro Granado	50	Vice-President	2005
Eudomario Carruyo	59	Internal Director	2005
Asdrubal Chávez	50	Internal Director	2005
Eulogio del Pino	48	Internal Director	2005
Déster Rodríguez	43	Internal Director	2005
Jesús Villanueva	56	Internal Director	2005
Iván Orellana	52	External Director	2005
Carlos Martínez Mendoza	50	External Director	2005
Bernard Mommer	62	External Director	2005
Antonio Simancas Cardozo	57	Chief Financial Officer	2005

Certain information on our current directors and executive officers is set forth below:

Rafael Ramírez Carreño
Minister of Energy and Petroleum of Venezuela and President of PDVSA

Rafael Ramírez is a Mechanical Engineer who graduated from the Los Andes University in 1989. He also holds a MSc. in Energy Studies from the Universidad Central de Venezuela. He began his career in the oil industry with Intevep, PDVSA’s research and development center, where he was initially assigned to work on the handling of Orinoco Belt extra-heavy crudes. Further assignments and postings to other subsidiaries provided him with wide experience in the development, coordination and management of engineering and construction projects. His

secondments abroad included the development, in the United States, of the Cardón refinery’s upgrading and expansion project and Nigeria’s Liquefied Natural Gas project, in France. Ramírez was the founding president of Enagas, the national gas entity charged with the responsibility of structuring the National Gas Plan and the design, development and promotion of the State policies for the sector.

In February 2002 he was appointed external director of Petróleos de Venezuela, and in July that year was sworn in as Minister of Energy and Mines by the Bolivarian Republic of Venezuela’s President Hugo Chávez. On 20th November 2004, under Presidential Decree 3264, he was named President of Petróleos de Venezuela, a position which he holds concurrently with that of Minister of Energy and Petroleum.

Luis Vierma

Vice-President of PDVSA

Luis Vierma has a Bachelor in Chemistry, from the Universidad Central de Venezuela in 1979. He obtained his MSc. in Geology (Petroleum Geochemistry) in 1984, from Indiana University at Bloomington. Between 1975 and 1978 he taught chemistry at the Central University’s Chemistry Department. From 1978 to 1981 he held the position of Exploration Geochemist at PDVSA’s research and development center. He was later appointed head of the Organic Geochemistry Laboratory, in which he became leader of Hydrocarbons Exploration Projects and, later, head of the Inorganic Chemistry Unit. In 1993 Vierma was named Manager of Annex XIII (Enhanced Recovery of Crudes using micro-organics) of the Ministry of Energy and Mines - US Department of Energy (DOE) Agreement. In 1995 he was appointed head of the Organic Geochemicals Section and, in 1997, head of the Geology Section. In 1998 he was leader of the Bosque-Bucare Project to implement the Shared Productivity Effort Strategy. In 1999 he became Exploration Business Manager, and in 2000 he was appointed Director of the Policies and Plans Office of the Vice-Ministry of Hydrocarbons at the Ministry of Energy and Mines. At the beginning of 2003 he is sworn in as Deputy Minister of Hydrocarbons, being also named external Director of Petróleos de Venezuela in March of that year, and later President of the Corporación Venezolana de Petróleo (CVP), Vice-President of PDVSA GAS, and a member of the CITGO Petroleum Corporation Board. In January 2005 he was appointed Vice-President of Exploration and Production of PDVSA.

Alejandro Granado

Vice-President of PDVSA

Alejandro Granado is a Refining Processes Engineer and graduated in 1981 from the Institute of Petroleum and Gas in Ploesti, Romania. He later obtained a Master of Science degree in Refining and Petrochemicals from the same institute. Granado joined the Venezuelan oil industry in 1981 as a process engineer in the Process Development department of INTEVEP, PDVSA’s research and development center. In 1985 he was seconded to UOP in Chicago as resident engineer for the BTX project. In 1987 he was appointed a member of the team assigned to Germany’s Veba Oel for the development of the HDH+® process, a heavy residue conversion technology. In 1990 he was seconded to British Petroleum in London to lead the process engineering group charged with the design of several the mixed ethers units for the Venezuelan refinery system. From 1991 to 1997 he held several managerial positions in the Process Engineering area at Intevep, and in 1997 he was posted to CITGO Petroleum Corporation as Technology Manager of that subsidiary’s refinery at Lemont, Illinois. He returned to INTEVEP in 2000, being appointed manager of the Process Engineering department. Later, he was in charge of the Conceptual and Basic Engineering Management until December 2002, when he was named Deputy General Manager of the Puerto La Cruz refinery. In July 2003 he was appointed Refining Director of PDVSA Eastern Division. In July 2004 he was appointed International and National Refining Director of PDVSA and he has been PDVMARINA Vice-President since 2004. In January 2005 he was appointed Vice President of PDVSA, responsible for the refining area both at a domestic and international level.

Eudomario Carruyo

Director of PDVSA

Eudomario Carruyo received a Public Accounting Degree from the Universidad del Zulia in 1972. He has completed several specialization and post-graduate courses in the areas of Finance and Management in Columbia University, in New York, and Michigan University, in Ann Arbor. He had a training assignment in international banking at Chase Manhattan Bank, in New York. He has 38 years of experience in the domestic oil and

petrochemical industry. He started his career in the Corporación Venezolana del Petróleo (CVP), a PDVSA subsidiary, in 1964. Between 1964 and 1987 he held the following positions: Corporate Treasury Manager, Corporate Comptroller Manager, Corporate Budget and Economic Evaluations Manager, Corporate Costs Manager, Finance Manager for the Western Division, Finance Manager for the San Tomé Area, Finance Manager for the El Palito Refinery and President of the Bidding Committee. In 1991 he was transferred to Palmaven, PDVSA’s affiliate, where he worked for six years (1992-1997), acting as Finance Manager and later as Director of this affiliate. Simultaneously, and as a Palmaven representative, he sat on the Boards of Directors of several of its businesses. In 1997 he retired from the oil industry and then re-entered as PDVSA’s Statutary Auditor from April 2000 until December 2002 (first as assistant and then as principal). In January 2003, he was appointed Finance Executive Director for PDVSA and held this position until June of the same year when he was designated Director of the following affiliates: CITGO Corporation, PDVSA Finance, PDVSA Insurance, PDV Holding, and APJ International. Since July 2003, he has acted as Pequiven Director, coordinating the closure of PDVSA and its affiliates’ fiscal year 2002 and the preparation of operational financial reports both for internal use and for the SEC. Simultaneously with his responsibilities at Pequiven, he also acts as Director of the following businesses and affiliates: Fertinitro, Monómeros Colombo-Venezolanos, Metor International, Produven, Super Octanos, Supermetanol, Tripoliven, Clorozulia, Coramer, Olefinas del Zulia, Polinter, Propilven, Pralca, Produsal, Servifertil, International Petrochemical Holding LTD (IPHL), International Petrochemical Sales Limited (IPSL), Copequim, Grupo Zuliano and Sofilago. He was appointed Director of PDVSA in January 2005, serving concurrently as Director of CITGO Petroleum Corporation, Director of PDVSA Petróleo S. A., Director of Deltaven S. A., Vice-President PDV Marina, President PDVSA Finance and President PDV Insurance.

Asdrúbal Chávez

Director of PDVSA

Asdrúbal Chávez graduated as a Chemical Engineer from Universidad de Los Andes in 1979. He joined the venezuelan oil industry in 1979 at PDVSA’s El Palito refinery, as Startup Engineer for PAEX, the refinery’s major expansion project. He held various positions in areas such as Industrial Services, Distillation and Specialties, Conversion and Treatment, Crude and Products Movement, Programming and Economics, and Process Engineering. In 1989 he was assigned to UOP, in the USA. In 1990 he was named Leader of the Project to expand El Palito’s Crude and Vacuum Distillation units. From 1995 to 1999 he held various supervisory and managerial positions, and in 2000 PDVSA’s Presidency seconded him on a temporary basis to the Ministry of Production and Commerce to assist it, first in the restructuring of the Ministry, and then in the Economic Constituent Process. In 2001 he was assigned to PDVSA’s Bitúmenes del Orinoco (BITOR) subsidiary as Human Resources Manager, and led the team that worked on the restructuring part of the company’s expansion project. In 2002 he was named Assistant to the BITOR Board of Directors, and in January 2003 he was appointed Manager of the El Palito Refinery. In August 2003 he was named Executive Director for Human Resources at PDVSA, and in March of 2004, he was appointed Executive Director for Trading and Supply, having also been leader of the team which negotiated the 2004-2006 Collective Labor Contract. In January 2005 he was appointed Director of PDVSA, responsible for Commerce and Supply and President of PDV Marina and BITOR, PDVSA’s subsidiaries and Director of CITGO Petroleum Corporation, PDVSA affiliate based in Houston, USA.

Eulogio Del Pino

Director of PDVSA

Eulogio Del Pino is Geophysical Engineer graduated from the Universidad Central de Venezuela in 1979, and with a MS degree in Oil Exploration from Stanford University in 1985. In 1979 he started his career on venezuelan oil industry at INTEVEP, PDVSA’s Technology and Research Center, were held different technical and supervisors positions. In 1990 he was appointed Latin America Technical Manager for Western Atlas Company. In 1991 he returned to Petróleos de Venezuela, where he held several managerial positions at Corpoven, another of PDVSA’s affiliates in the recent past. In 1997 he was appointed Exploration and Delineation Manager of PDVSA Exploration and Production. He had the responsibility to coordinate the PDVSA’s restart Offshore Exploration Campaign in the Plataforma Deltana in 2001. Later in 2003 he was appointed General Manager of Strategic Associations from de Corporación Venezolana de Petróleo, PDVSA’s affiliate, in charge of representing at the Strategic Association of the Orinoco Oil Belt and in 2005 he was named Director of PDVSA and President of PDVSA CVP. Del Pino has been elected for President and Vice President of the Venezuelan Society of Geophysical

Engineers (1990-1994), Vice-President of the US’s Society of Exploration Geophysicists (1996-1997), and Founder and Coordinator of the Latin American Geophysical Union. Del Pino was a professor on both the pre-graduate and post-graduate level at the Universidad Central de Venezuela and the Universidad Simón Bolívar, in Caracas.

Déster Rodríguez

Director of PDVSA

Dester Rodríguez is an Army Colonel with a bachelor’s degree in Military Science and Arts from the Military Academy of Venezuela. He completed Systems Engineering studies at the Universidad Experimental de las Fuerzas Armadas (Experimental University of the Armed Forces). In 1997 he was appointed Head of Personnel of the Military Engineering School of the Army. In 1998 he was named Head of the Army Personnel Registry and Control Division. In 1999 he was designated General Director of the Information Technology Ministerial Office at the Ministry of Education, Culture, and Physical Education, a position held simultaneously with that of President of the Fundación Bolivariana de Informática y Telemática (Bolivarian IT and Telecommunications Foundation) since 2001. In December 2002 he was appointed a member of PDVSA’s Restructuring Committee. In March 2003 he was named Director of Petróleos de Venezuela, serving concurrently as Director of CITGO Petroleum Corporation, Vice-President of Refinería Isla, a member of the Board of PDV Holding and President of CIED and COMMERCHAMP.

Jesús Villanueva

Director of PDVSA

Jesús Villanueva is a Licentiate in Public Accounting and received a Master degree in Hydrocarbons Economy and Management from Universidad Central de Venezuela in 1988. He started his professional activities in 1974 as Assistant in the Auditing Division of Espiñeira, Sheldon y Asociados (Price Waterhouse Coopers) where he worked until 1982. He joined the venezuelan oil industry in 1982 at Meneven, then a PDVSA subsidiary. During his professional career he has held different supervising and managerial positions in San Tomé, Anaco, Puerto La Cruz and Caracas, in Auditing and Finances for Meneven and Corpoven. Beginning in February 2002, he acted as Principal Director for PDVSA and later on went back to his former position as General Auditor. He was appointed Director of PDVSA in January 2005. He has been internationally certified as Internal Auditor by the Institute of Internal Auditors (1999) and a Certified Fraud Examiner (2004).

Iván Orellana

General Director for Hydrocarbons of the Ministry of Energy and Petroleum Venezuelan Governor for OPEC

Director of PDVSA

Iván Orellana is a Chemical Engineer who graduated from Universidad Simón Bolívar (1975). He completed post-graduate studies in Strategic Planning in Brunel University, London in 1994; Oil and Natural Gas Supply and Trade in Oxford, UK in 1994; Administrative Law in Universidad de Salamanca, Spain, in 2003; and Private International Law in Universidad de Salamanca in 2004. He started his career in the hydrocarbons sector in 1975, holding different supervisory and engineering positions. In 1988 he worked as consultant for the gas sector in the Exploration and Production Coordinating Department of PDVSA Gas. In 1994 he was appointed Planning Manager for PDVSA Gas and between 1997 and 2001 he worked as Senior Planning Consultant for Energy and Regulation of Energy Markets inside PDVSA’s Corporate Planning Management. Between 2002 and 2003, he acted as Trade Environment Analysis Manager in PDVSA’s Planning Executive Direction and he has been the Venezuelan National Representative in Organization of the Petroleum Exporting Countries (OPEC) Economic Commission since 2003. He is currently the Venezuelan Governor for OPEC and Chairman of OPEC’s Governors Board and as well the General Director for Hydrocarbons in the Ministry of Energy and Petroleum. He was appointed External Director for PDVSA’s Board of Directors in January 2005 in the area of International Business. He has also been Coordinator for the studies to establish PDVSA and Venezuela’s strategic positioning in the Liquefied Natural Gas (LNG) Business in the Atlantic Basin, Consultant to the President of the National Gas Agency and PDVSA’s president in the process of Energy Services Regulation for Venezuela and Consultant to the Ministry of Energy and Mines and PDVSA in the bidding process for the Mariscal Sucre LNG Project.

Carlos Martínez Mendoza

Director of PDVSA

Carlos Martínez Mendoza received a Licentiate in Military Sciences and Arts from the Military Academy of Venezuela in 1975 as a member of the “Simón Bolívar II” group. He belongs to the Infantry branch of the Army. He studied Command and Staff in the “Escuela Superior de Guerra del Ejército” in Argentina in 1990 and also holds a Master Degree in Security and National Defense. He took a postgraduate course on Strategic Planning and Management, as well as a course on Defense Resource Management in the Center for Defense Hemispheric Studies in the USA. He has held positions complementary to his military rank, such as Secretary of the Nation’s Defense Council and Director of the Presidential Office of the Bolivarian Republic of Venezuela. He is currently President of the Zulia Region Development Corporation (Corpozulia) and Carbozulia. He is Vice-President of the “Sofioccidente” Investment Bank of Venezuela. In 2005 he was appointed external Director of PDVSA.

Bernard Mommer

Director of PDVSA

Bernard Mommer holds a masters degree in mathematics and a doctorate in social science, both from the University of Tübingen, Germany. He has been a university teacher and researcher for many years at different Venezuelan universities. From 1991 to 1995 he was senior advisor to Petróleos de Venezuela and the Strategic Planning Co-ordinator. From 1995 to 2001 he was a senior research fellow of the Oxford Institute for Energy Studies and of St. Antony’s College, Oxford. He also acted as an advisor to the Venezuelan Minister of Energy and Mines from 1999 to 2000, and as a consultant to the Secretary General of OPEC in Vienna in 2002. Previous to his appointment at PDV UK he was advisor to the President of PDVSA. Outstanding amongst his publications are Die Ölfrage [The Petroleum Question] (1983: Institut für Internationale Angelegenheiten der Universität Hamburg, Nomos Verlagsgesellschaft Baden-Baden), El petróleo en el pensamiento económico venezolano - Un ensayo [Oil in the Economic Thought of Venezuela – An Essay] (Co-author Asdrúbal Baptista; Prologue by Arturo Uslar Pietri. Ediciones IESA, Caracas, 1987); and The New Governance of Venezuelan Oil (1998: Oxford Institute for Energy Studies), Global Oil and the Nation State that was published by Oxford University Press, on behalf of the Oxford Institute for Energy Studies, in 2002. In 2004, the Ministry of Energy and Mines published his book “El mito de la Orimulsión”. In 2005, he was appointed Director of PDVSA and Deputy Minister of Hydrocarbons.

Antonio Simancas Cardozo

Chief Financial Officer

Mr. Simancas is an accountant who graduated from the Central University of Venezuela in 1973. He holds a Master’s degree in economic sciences from Oklahoma State University and specializations in business law from Santa María University, Venezuela and in management and marketing from the University of Tennessee.

Mr. Simancas has worked as a business consultant, Finance Manager for a subsidiary of the Cisneros Group, General Director of the Venezuelan Institute of Social Security, Controller for the Social Investment Fund of Venezuela, Technical Manager and General Manager for the Superintendence of Banks, Controller for the National Council for Scientific and Technological Investigations. At PDVSA, he has been Petroleum Accounting Corporate Manager, Accounting and Budget Manager in a production division, Finance Manager in Bariven and Financing Manager for PDVSA’s subsidiary Bariven.

6.B Compensation

For the year ended December 31, 2003, the aggregate amount paid by PDVSA as compensation to its directors and executive officers for services in all capacities was approximately $1.07 million (based on the 2003 average exchange rate of Bs. 1,600.00 to $1). For the year ended December 31, 2004, the aggregate amount paid by PDVSA as compensation to its directors and executive officers for services in all capacities was approximately $1.47 million (based on the 2004 average exchange rate of Bs. 1,893.00 to $1).

6.C Board practices

Our directors are appointed for an initial term of 2 years, which may be extended indefinitely until a new board of directors is appointed. We have not entered into any service or employment contracts with any of our directors and executive officers.

Audit Committee Structure and Objectives

Basic Function

The Audit Committee assists the Board of Directors of PDVSA in the execution of its responsibilities, regarding the monitoring of the quality and sufficiency of the internal control system and the protection of the viability of PDVSA, both nationally and internationally. The Committee carries out its basic function through the knowledge, evaluation and follow up as follows:

• Risk analysis for the different businesses.

• Follow up on the behavior and tendencies of the components of the internal control system, in the Venezuelan and international operations, and the capacity of the system to minimize risks.

• The performance, results and efficacy of PDVSA’s corporate control units.

• Meeting the requirements of laws and regulations, issued both in Venezuela and abroad, including the requirements of the Securities and Exchange Commission and the Sarbanes-Oxley Act and the Internal Norms and Procedures.

• The results of the internal and external audits.

• Corporate governance aspects, including following up and analying results of our accountability programs.

• Quality and integrity of Corporate Financial Information.

Authority

The Board of Directors of PDVSA has granted the Audit Committee full authority to execute its assigned responsibilities. The Audit Committee may utilize the services of the corporate control units, the external auditors, independent consultants, or any other group or internal or external resource with the necessary expertise required to perform relevant studies or investigations.

Organization

The Audit Committee is comprised of six members, who are appointed by the Board of Directors. The president of the Committee is the President of PDVSA, whereas the other two members are external directors of PDVSA.

The General Auditor of PDVSA is the secretary of the Committee. The president of the Committee is responsible for setting the direction and priorities of the issues seen by the Committee. The Controller, the Loss Control Manager and the Corporate Legal Adviser assist in meeting on a regular basis. Other corporate executives, including the CFO, attend the meetings on special occasions.

Main Functions

• to assure the adequacy and sufficiency of the internal control system including the control environment, structure and activities, and the processes of monitoring and information,

• to recommend to PDVSA’s board of directors any course of action regarding the main issues of the internal control system, including actions required to improve corporate information systems,

• to orient and support the activities of the corporate control units of PDVSA,

• to approve the internal audit policy and norms, including the relationship between corporate internal audit and the audit units within subsidiaries or joint ventures,

• to insure the application of general auditing standards issued by the Venezuelan government,

• to insure and preserve the independence and objectivity of the internal audit function,

• to know, review and approve the structure, plans and results of the corporate control units of PDVSA,

• to know and establish various courses of action regarding economic, legal, environmental, asset preservation and any other issue that could affect the performance of PDVSA,

• to evaluate annually the performance of the external auditors and to consider whether they should remain as external auditors,

• to review along with the external auditors their opinion on the financial statements of the company, the quality of the internal control system, the main risk areas and the integrity of the financial and operating reports,

• to review the effectiveness of the corporate governance and results accountability system,

• to review fraud and other such cases in the company, as well as to assure compliance of the conflict of interest and ethical conduct policies of PDVSA, and

• to review annually the performance of the Committee and to submit its activity report to the board of directors.

6.D Employees

The number of PDVSA employees and their locations of employment for 2003, 2002 and 2001 are as follows:

At December 31	Total Number of Employees	In Venezuela	Abroad
2003	33,998	28,841	5,157
2002	45,683	40,133	5,550
2001	46,425	40,945	5,480

At December 2004 approximately 27% of our Venezuelan work force was unionized and belonged to one of four principal unions: the Federación de Trabajadores Petroleros, Químicos y Similares (63.0%), the Federación Nacional Bolivariana de trabajadores Petroleros, Petroquímicos, del Gas, sus similares y conexos de Venezuela (6.7%), the Sindicato Nacional de Trabajadores de la Industria Petrolera (13.4%), or the Federación de Trabajadores de la Industria de los Hidrocarburos (16.9%). Our management, our employees based in our headquarters and our security personnel are generally not affiliated with any union.

For our non-unionized workers, we have a special compensation program. This program establishes a variable factor for a portion of the employees’ compensation, which is tied to individual performance based on predetermined targets and goals, as well as on our financial results. However, for 2003 the compensation program was based on a bonus payment, which recognized individual performance.

6.E Share ownership

PDVSA’s common stock is not publicly traded and, as of October 7, 2005, we had 51,204 shares outstanding. All of our issued and outstanding shares of common stock are owned by the Bolivarian Republic of Venezuela.

Item 7. Major Shareholders and Related Party Transactions

7.A Major Shareholders

Control of Registrant

PDVSA is the national oil and gas company of the Bolivarian Republic of Venezuela. PDVSA was formed by the Venezuelan government in 1975 pursuant to the Organic Law that reserves for the state the industry and trade of hydrocarbons (the “Nationalization Law”), and its operations are supervised by Venezuela’s Ministry of Energy and Petroleum, who now also serves as the President of PDVSA. The Ministry of Energy and Petroleum establishes our general policies and approves our production levels, capital expenditures and operating budgets annually, while our board of directors is responsible for implementing the policies established by the government of Venezuela.

Since its formation, PDVSA has been operated as a commercial entity, vested with commercial and financial autonomy. Venezuela is not legally liable for PDVSA’s obligations, including PDVSA’s guarantees of indebtedness or obligations of its subsidiaries, nor for the debt or obligations of PDVSA’s subsidiaries. Under the 1999 Constitution of Venezuela, Venezuela must retain exclusive ownership of the shares of PDVSA. However, the Constitution does not require Venezuela to retain ownership of the shares of PDVSA’s subsidiaries or of its interests in various exploration and joint venture arrangements. Through its subsidiaries, PDVSA supervises, controls and develops the petroleum, petrochemical, gas, coal and Orimulsion® industries in Venezuela. These activities are complemented by PDVSA’s operating companies established abroad, which are responsible for refining and marketing activities in North America, Europe and the Caribbean. See note 1(a) to of consolidated financial statements, included under “Item 18. Financial Statements.”

PDVSA’s oil-related activities are governed by the Hydrocarbons Law, which came into effect in January 2002. PDVSA is subject to regulations adopted by the executive branch of the Venezuelan government and other laws of general application, such as the Commercial Code of Venezuela. PDVSA and its Venezuelan subsidiaries are organized under the Commercial Code, which regulates the rights and obligations of Venezuelan commercial companies. Under the Commercial Code, PDVSA and Venezuelan subsidiaries are permitted to develop and execute their shareholder’s objectives as corporate entities rather than governmental agencies.

PDVSA’s gas-related activities are regulated by the Organic Law of Gas Hydrocarbons of September 1999 and its regulations dated June 2000.

PDVSA, its Venezuelan subsidiaries engaged in the conduct of activities reserved to the government pursuant to the Nationalization Law, and its foreign subsidiaries are not subject to the authorization process set forth in the Finance Administration for the Public Sector Law enacted on September 5, 2000, which establishes the regulations applicable to borrowing and other forms of financing by Venezuelan public entities.

Ownership of Reserves

All oil and hydrocarbon reserves within Venezuela are owned by Venezuela and not by PDVSA. Under the Nationalization Law, every activity related to the exploration, exploitation, manufacture, refining, transportation by special means and domestic and foreign sales of hydrocarbons and their derivatives is reserved to the government of Venezuela. PDVSA was created as the entity that coordinates monitors and controls all operations related to hydrocarbons.

7.B Related party transactions

See note 18 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Item 8. Financial Information

8.A Consolidated Statements and Other Financial Information

8.A.1 See “Item 18. Financial Statements.”

8.A.2 See “Item 18. Financial Statements.”

8.A.3 See report of the independent registered public accounting firms beginning on page F-1.

8.A.4 Substantially all of our revenues are derived from export sales. See “Item 3.A Selected financial data,” and note 18 to our consolidated financial statements, included under “Item 18. Financial Statements.”

8.A.7 Legal proceedings

Action by independent oil producers

In August 1999, the U.S. Department of Commerce rejected a petition filed by a group of independent oil producers to apply antidumping measures and countervailing duties against imports of crude oil from Venezuela and some other countries. The petitioners appealed this decision before the U.S. Court of International Trade based in New York. On September 19, 2000, the Court of International Trade remanded the case to the Department of Commerce with instructions to reconsider its August 1999 decision. The Department of Commerce was required to make a revised decision as to whether or not to initiate an investigation. The Department of Commerce appealed to the U.S. Court of Appeals for the Federal Circuit, which dismissed the appeal as premature on July 31, 2001. The Department of Commerce issued its revised decision, which again rejected the petition, in August 2001. The revised decision was affirmed by the Court of International Trade on December 17, 2002. In February 2003, the independent oil producers appealed the Court of International Trade’s decision to the Federal Circuit Court. On January 2004, the U.S. Court of Appeals for Federal Circuit affirmed the decision of the Court of International Trade.

LYONDELL-CITGO

In February 2002, LYONDELL-CITGO commenced an action against PDVSA and PDVSA Petróleo, in the United States District Court for the Southern District of New York seeking damages for alleged breaches of the long-term crude oil supply agreement between LYONDELL-CITGO and Lagoven (subsequently merged into PDVSA Petróleo) and the supplemental supply agreement, between LYONDELL-CITGO and PDVSA. Both agreements are dated May 5, 1993 and expire in 2017. On May 31, 2002, PDVSA and PDVSA Petróleo filed a motion to dismiss the case. On August 6, 2003, the judge dismissed one of the ten counts in the complaint, allowing the remaining counts to proceed through early stages of litigation. The parties engaged in extensive discovery beginning in November 2003. In the course of expert discovery, on September 30, 2004, one of LYONDELL-CITGO’s retained experts filed a report listing the amount of liquidated damages owed by PDVSA and PDVSA Petróleo to LYONDELL-CITGO through September 2004 as $125,117,465. For the same period, LYONDELL-CITGO’s expert calculated the amount of actual damages as $258,447,787 to $259,743,967, depending on the method used to calculate interest. LYONDELL-CITGO also claims additional unspecified amounts for attorneys’ fees and costs. Discovery was formally concluded on October 1, 2004. On October 1 and October 6, 2004, the magistrate judge issued orders directing PDVSA and PDVSA Petróleo to produce all Board of Directors minutes and related documents to LYONDELL-CITGO. PDVSA informed the magistrate judge that it could not comply with his order because granting LYONDELL-CITGO unrestricted access to PDVSA’s Board of Directors materials violated Venezuelan law. The magistrate judge entered an adverse inference sanction against PDVSA and PDVSA Petróleo, ordering that the court may infer that the Board of Directors’ documents were unfavorable to PDVSA and favorable to LYONDELL-CITGO. The magistrate judge also ordered that the court may give the strongest weight

to the evidence already in the case in favor of LYONDELL-CITGO, but may also consider any evidence presented by PDVSA to explain why it did not produce the Board of Directors materials. The judge affirmed the magistrate judge’s adverse inference instruction on April 29, 2005. Meanwhile, on October 22, 2004, both parties filed motions for summary judgment with the court, which have been fully briefed. These motions are still pending. Management of the companies intends to contest vigorously LYONDELL-CITGO’s claims. See note 20 of our consolidated financial statements, included in “Item 18. Financial Statements.”

Action in Grenada

In April 11, 2003, a legal action was filed against PDVSA and its subsidiaries PDVSA Petróleo, PDVSA Finance Ltd. and CITGO, in the federal district court of Denver, Colorado. The plaintiff is a U.S. oil and gas exploration and production company that has allegedly entered into an exclusive offshore license agreement with the government of Grenada to explore, develop, produce and market oil and/or natural gas in 4.75 million offshore acres between Grenada and Venezuela. The plaintiff alleges that PDVSA has interrupted and otherwise interfered with its ability to develop and market Grenada’s oil and natural gas resources in violation of the U.S. antitrust laws. The plaintiff seeks damages in an amount to be established at trial that it believes should exceed $100 million. The companies deny the allegations and intend to contest the case vigorously if it proceeds. On November 2003, the plaintiff filed a Notice of Dismissal, without prejudice, with respect to PDVSA Finance, Ltd. On September 30, 2004, the court decided in favor of PDVSA. Nevertheless, the plaintiff appealed the decision and therefore the matter is still pending. Management and their legal counsel believe that the companies have substantial defenses.

Employment actions related to the work stoppage

During December 2002 and first months of 2003, there was a work stoppage by a significant number of workers and employees of PDVSA and its subsidiaries in Venezuela. This resulted in the termination of employment, effective January 1, 2003, of approximately 18,000 employees (of our then total labor force of 45,000). Based on the opinion of PDVSA’s management and legal counsel, the terminations were in accordance with Venezuelan labor law. All significant outstanding employee benefits in accordance with PDVSA’s employment benefits and Venezuelan labor law were accrued as of December 31, 2003 and 2002. The above-mentioned former PDVSA employees have filed a petition for reinstatement with the labor courts. Based on their legal counsel’s opinion, management believes that the resolution of this matter will not have a material effect to the Company’s financial position or results of operations. See note 20 to our consolidated financial statements, included in “Item 18. Financial Statements.”

INTESA

PDVSA previously outsourced its information technology services to INTESA based on a joint venture and a services agreement. INTESA is a Venezuelan company owned 60% by SAIC Bermuda Ltd. and 40% by PDV IFT, a subsidiary of PDVSA. On June 28, 2002, PDVSA gave notice of termination of the services agreement, in accordance with the contract. PDVSA has proposed a plan to jointly liquidate INTESA and to honor all valid obligations with the employees and providers. PDVSA has been assigned and has paid a significant portion of INTESA’s obligations with providers, which will be offset against the debt that PDVSA has with INTESA. Management and their legal counsel believe that the liquidation of INTESA will not have a material effect on the Company’s financial position or results of operations.

Action against PDVSA Petróleo

In May 2003, an arbitration proceeding in the International Court of Arbitration was commenced against PDVSA Petróleo in connection with a dispute arising under an alleged contract for the sale and purchase of 50,000 metric tons of unleaded gasoline dated February 19, 2003. The plaintiffs are claiming damages amounting to $14 million. Management and their legal counsel have denied the allegations and have contested the claims vigorously. Management and their legal counsel believe that they have substantially responded to the claims asserted.

Additional legal actions

Additionally, the Company is involved in various other claims and legal actions in the ordinary course of business amounting to $2,900 million. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or liquidity.

Based on an analysis of the available information, a provision as of December 31, 2003 and 2002, amounting to $380 million and $46 million, respectively, is included in accrued and other liabilities related to all the contingencies described above (see note 17 to our consolidated financial statements, included in “Item 18. Financial Statements.”) If known lawsuits and claims were to be determined in a manner adverse to the Company, and in amounts greater than the Company’s accruals, then such determinations could have a material adverse effect on the Company’s results of operations in a given reporting period. Although it is not possible to predict the outcome of these matters, management, based in part on advice of its legal counsel, does not believe that it is probable that losses associated with the proceedings discussed above that exceed amounts already recognized, will be incurred in amounts that would be material to the Company’s financial position or results of operations.

8.A.8 Dividend policy

See note 15 to our consolidated financial statements, included under “Item 18. Financial Statements.”

Item 9. The Offer and Listing

9.A.4

9.C Markets

PDVSA Finance’s senior notes are solely obligations of PDVSA Finance and are not obligations of, or guaranteed by, PDVSA. PDVSA Finance’s 6.650% Notes due 2006, 9.375% Notes due 2007, 6.800% Notes due 2008, 9.750% Notes due 2010, 7.400% Notes due 2016, 9.950% Notes due 2020 and 7.500% Notes due 2028 are listed on the Luxembourg Stock Exchange. PDVSA Finance’s 8.500% Notes due 2012 are not listed on any securities exchange.

Item 10. Additional Information

10.B Memorandum and articles of association

PDVSA incorporates by reference its memorandum and articles of association filed on Form F-1 on June 2, 1993 with the U.S. Securities and Exchange Commission.

10.D Exchange controls

Foreign Exchange Agreements

Article 89 of the regulations of the BCV stipulates that the BCV must sell non-Venezuelan currency to us on a priority basis to meet our foreign exchange requirements, subject to the annual foreign currency budget approved by the shareholders. We are the only entity accorded such priority under the regulations of the BCV, which was approved by the Venezuelan Congress in 1992, although the article establishing our priority to foreign exchange was originally incorporated into the regulations of the BCV in 1983 and effectively reaffirmed in 1992.

The priority access has been formalized through a foreign exchange agreement between the Ministry of Finance and the BCV. The agreement requires us to sell our foreign exchange receipts to the BCV within 48 hours of receipt, except that we may maintain a foreign currency working capital fund of up to the amount authorized by

the board of directors of the BCV (currently $600 million). We may use amounts contained in this fund to cover our obligations and operating costs in foreign currency and external debt service.

Current revenues and the working capital fund have always proved sufficient to meet all foreign currency requirements as they became due, and we have never experienced payment delays as a result of foreign exchange controls.

Foreign Exchange Budget

We are required to submit a foreign exchange budget for approval by our shareholder each year. Foreign exchange inflows are based on projected export volumes and prices, as well as proceeds from any debt issuance, while outflows are based on projected purchases of imported goods and services, as well as payments of principal of and interest on foreign currency denominated debt. In 2003, our foreign exchange inflows totaled $19,517 million, while outflows totaled $5,740 million.

10.E Taxation

United States holders of PDVSA Finance Notes are not subject to Venezuelan taxes, by reason of withholding or otherwise, on payments made by PDVSA Finance pursuant to the PDVSA Finance Notes.

On January 25, 1999, representatives from the United States and Venezuela signed an income tax treaty for the avoidance of double taxation. Both countries exchanged instruments of ratification on December 30, 1999. The treaty has been fully in force since 2000.

Item 11. Quantitative and Qualitative Disclosures about Market Risk

Introduction

We are exposed to hydrocarbon price fluctuations, interest rate fluctuations and foreign currency exchange risks. To manage these exposures, we have defined certain benchmarks consistent with our preferred risk profile for the environment in which we operate and finance our assets. We do not attempt to manage the price risk related to all of our inventories of hydrocarbon products. As a result, at December 31, 2003, we were exposed to the risk of broad market price fluctuations with respect to a substantial portion of our hydrocarbon inventories. The following disclosure does not attempt to quantify the price risk associated with such commodity inventories. All matters related to market risk are managed by our international subsidiaries.

Commodity Derivative Instruments

We balance our crude oil and refined products supply and demand and manage a portion of our price risk by entering into petroleum commodity derivatives through CITGO. Generally, CITGO’s risk management strategies qualified as hedges through December 31, 2000. Effective January 1, 2001, we decided not to elect hedge accounting. Petroleum Marketing International, A.V.V., a direct trading subsidiary of PDVSA in Aruba, and PMI Panama, S.A., a direct trading subsidiary of PDVSA in Panama, have limited involvement with commodity derivatives. Both these entities manage commodity price risks associated with crude oil or refined products that arise out of their respective core business activities. These entities do not use derivative financial instruments for trading or speculative purposes.

In December 1999, PDVSA Trading, S.A. was incorporated as a direct subsidiary of PDVSA in Venezuela primarily to manage commodity price risk associated with derivatives. This subsidiary began its operations in March 2000. However, this subsidiary has become inactive and since 2003, all our derivative instruments operations are being managed by CITGO.

The table below presents contractual amounts with open positions at December 31, 2003, for commodity derivatives, and includes futures purchased and futures sold.

Non Trading Commodity Derivatives
Open Positions at December 31, 2003

Commodity	Derivative	Maturity Date	Volumes of Contracts (1) Long/(Short		Contract Value (3)		Market Value (2) (3)
					Asset/(Liability)
					($ in millions)

No Lead Gasoline	Futures Purchased	2004	315		12.2		12.4
	Futures Sold	2004	(396	)	(15.6	)	(15.6	)
	Listed Call Options Purchased	2004	750		—		1.8
	Listed Call Options Sold	2004	(750	)	—		(1.2	)
	Forward Purchase Contracts	2004	2.117		80.2		83.0
	Forward Sale Contracts	2004	(1,842	)	(71.2	)	(73.3	)

Distillates	Futures Purchased	2004	2.211		73.6		82.7
	Futures Purchased	2005	4		0.1		0.1
	Futures Sold	2004	(400	)	(15.3	)	(15.4	)
	OTC Call Options Purchased	2004	6		—		—
	OTC Put Options Purchased	2004	6		—		—
	OTC Call Options Sold	2004	(6	)	—		—
	OTC Put Options Sold	2004	(6	)	—		—
	Forward Purchase Contracts	2004	1,643		60.5		60.7
	Forward Sale Contracts	2004	(1,273	)	(46.2	)	(46.8	)

Crude Oil	Futures Purchased	2004	100		3.3		3.3
	Futures Sold	2004	(100	)	(3.3	)	(3.3	)
	Forward Purchase Contracts	2004	1,287		39.0		39.4
	Forward Sale Contracts	2004	(822	)	(27.0	)	(26.7	)

(1) 1,000 barrels per contract

(2) Based on actively quoted prices.

(3) Fair value is represented by market value less contract value.

Non-Trading Commodity Derivatives
Open positions at December 31, 2002

Commodity	Derivative	Maturity date	Volumes of Contracts (1) Long/(Short)		Contract Value (4) (6)		Market Value (5) (6)
					Asset/(Liability)
					($ in millions)

No Lead Gasoline	Futures Purchased	2003	564		19.9		20.6
	Futures Sold	2003	(1,023	)	(35.3	)	(37.6	)
	Listed Options Purchased	2003	1,225		—		4.2
	Listed Options Sold	2003	(2,225	)	—		(5.5	)
	Forward Purchase Contracts	2003	2,577		89.2		92.5
	Forward Sales Contracts	2003	(2,364	)	(81.3	)	(86.2	)

Distillates (1)	Futures Purchased	2003	2,227		73.4		78.7
	Futures Purchased	2004	31		0.8		0.9
	Futures Sold	2003	(2,953	)	93.2		(96.7	)
	OTC Options Purchased	2003	66		—		0.1
	OTC Options Sold	2003	(66	)	—		(0.1	)
	OTC Swaps (Pay Fixed/Receive Float) (3)	2003	12		—		—
	OTC Swaps (Pay Float/Receive Fixed) (3)	2003	(75	)	—		—
	Forward Purchase Contracts	2003	3,134		106.5		111.0
	Forward Sale Contracts	2003	(2,944	)	(98.1	)	(104.7	)

Crude Oil	Futures Purchased	2003	1,986		51.2		54.5
	Futures Sold	2003	(1,476	)	(41.8	)	(45.3	)
	Listed Options Purchased	2003	2,250		—		2.3
	Listed Options Sold	2003	(3,150	)	—		(3.1	)
	OTC Swaps (Pay Float/Receive Fixed) (3)	2003	(3,500	)	—		(3.0	)
	Forward Purchase Contracts	2003	5,721		160.8		174.4
	Forward Sale Contracts	2003	(4,412	)	(129.8	)	(137.2	)

Natural Gas (2)	Listed Options Purchased	2003	85		—		0.1
	Listed Options Sold	2003	(40	)	—		(0.1	)

Propane	OTC Swaps (Pay Fixed/Receive Float) (3)	2003	75		—		0.5
	OTC Swaps (Pay Float/Receive Fixed) (3)	2003	(300	)	—		(1.5	)

(1) 1,000 barrels per contract.

(2) Ten thousand of mmbtu per contract.

(3) Floating price based on market index designated in contract; fixed price agreed upon at date of contract.

(4) Weighted average price.

(5) Based on actively quoted prices.

(6) Fair value is represented by market value less contract value.

Debt Related Instruments

Interest Rate Risk

We enter into various interest rate swap agreements to manage the risks related to interest rate fluctuations on our debt.

On January 28, 2000, PDVSA Finance entered into an interest rate swap agreement to manage the risks related to interest rate fluctuations in respect of its Euro 200 million 6.250% notes due 2002 through 2006 issued on April 8, 1999. The agreement provides protection to PDVSA Finance in respect of interest and principal payments from a possible appreciation of the Euro relative to the U.S. dollar during the terms of the notes. The agreement contains a knock-in provision that eliminates protection to PDVSA Finance, in respect of principal payments above a 1.09 U.S. dollar/Euro exchange rate if during the term of the agreement the U.S. dollar/euro exchange rate reaches or exceeds 1.2.

CITGO has fixed and floating U.S. currency denominated debt. CITGO uses interest rate swaps to manage its debt portfolio toward a benchmark of 40% to 60% fixed rate debt to total fixed and floating rate debt. These instruments have the effect of changing the interest rate with the objective of minimizing CITGO’s long-term costs. At December 31, 2003 and 2002, CITGO’s primary exposures were to LIBOR and floating rates on tax exempt bonds.

For interest rate swaps, the table below presents notional amounts and interest rates by expected (contractual) maturity dates. Notional amounts are used to calculate the contractual payments to be exchanged under the contracts.

Non-Trading Interest Rate Derivatives
Open positions at December 31, 2003

Variable Rate Index	Expiration Date	Fixed Rate Paid (%)	Notional Principal Amount
			($ million)
J.J. Kenny	February 2005	5.30	12
J.J. Kenny	February 2005	5.27	15
J.J. Kenny	February 2005	5.49	15
			42

The fair value of the interest rate swap agreements at December 31, 2003, based on the estimated amount that we would receive or pay to terminate the agreements as of that date and taking into account current interest rates was a loss of $2 million, the offset of which is recorded in other current liabilities.

Generally, we do not enter into interest rate swaps with respect to debt incurred by PDVSA, other than with respect to debt of CITGO or PDVSA Finance. The table below presents our principal cash flows and related weighted average interest rates by expected maturity date. Weighted average variable rates are based on implied forward rates in the yield curve at the reporting date.

Short-Term and Long-Term Debt
at December 31, 2003

Expected Maturities	Fixed Rate Debt	Average Fixed Interest Rate	Variable Rate Debt	Average Variable Interest Rate
	($ in millions)	%	($ in millions)	%

2004	376	7.65	373	2.54
2005	417	8.24	335	2.31
2006	417	8.13	432	4.48
2007	296	8.23	340	2.00
2008	397	7.95	334	1.32
Thereafter	2,549	8.41	748	3.68
Total	4,452	8.25	2,562	2.94
Fair Value	4,361

Short-Term and Long-Term Debt
at December 31, 2002

Expected Maturities	Fixed Rate Debt	Average Fixed Interest Rate	Variable Rate Debt	Average Variable Interest Rate
	($ in millions)	%	($ in millions)	%

2003	1,064	7.87	753	4.48
2004	372	7.90	387	4.10
2005	411	8.48	535	5.01
2006	463	8.17	283	4.45
2007	296	8.37	263	4.55
Thereafter	2,369	7.86	1,047	7.22
Total	4,975	7.97	3,268	5.40
Fair Value	7,631

Foreign Exchange Risk

The dollar is our reporting currency, since a significant portion of our revenues and debt, as well as the majority of our costs, expenses and investments are denominated in dollars. We generally do not enter into foreign currency derivative transactions to hedge against movements in exchange rates. We are, however, exposed to foreign currency exchange risk associated with our recoverable value added tax receivables, notes and accounts receivable, and long-term and short-term debt denominated in currencies other than the dollar, as summarized below:

	At December 31, 2003
Currency	Assets	Liabilities	Net
	($ in millions)

Venezuelan bolivars	6,260	4,459	1,801
Euros	52	150	(98	)
Other currencies	78	320	(242	)

	At December 31, 2002
Currency	Assets	Liabilities	Net
	($ in millions)

Venezuelan bolivars	6,495	5,272	1,223
Euros	195	172	23
Other currencies	5	414	(409	)

At December 31, 2003, we had approximately $396 million of short-term and long-term debt denominated in currencies other than dollars, as summarized below:

Currency		At December 31, 2003
		($ in millions)

Bolivars		3
Euros		113
Yen		280

At December 31, 2002, we had approximately $464 million of short-term and long-term debt denominated in currencies other than dollars, as summarized below:

Currency		At December 31, 2002
		($ in millions)

Bolivars		42
Euros		172
Yen		250

Item 12. Description of Securities Other than Equity Securities

Not applicable.

PART II

Item 13. Defaults, Dividend Arrearages and Delinquencies

PDVSA Finance is currently in the process of finalizing its unaudited financial statements for the quarter ended June 30, 2005 and, accordingly, has not provided such financial statements to the trustee within 90 days of the quarter end, as required by the terms of its senior indenture, as supplemented. Failure to do so constitutes an event of default under the terms of its senior indenture, which event of default would be cured upon the delivery of such financial statements to the trustee.

Further, on October 4, 2005, PDVSA Finance was advised by its external auditors that its audited financial statements for the year ended December 31, 2004 may have to be restated in order to reflect, as an expense, certain costs and premiums that were paid by its affiliate and our subsdiary, PDVSA Petroleo, S.A., in connection with the cash tender offer for its outstanding notes in 2004. It is unclear whether the restatement of its financial statements that were previously provided to the trustee on a timely basis would constitute an event of default under the terms of its senior indenture, as supplemented. Even if one were to conclude that such restatement would vitiate its earlier compliance with its reporting requirements under its senior indenture, as supplemented, its delivery of restated financial statements to the trustee by December 3, 2005 would, under the terms of its senior indenture, as supplemented, cure any breach of covenant by PDVSA Finance in this respect, thus preventing an event of default. If its financial statements for the year ended December 31, 2004 were to be restated, it is anticipated that such restatement will be completed promptly and, in any event, by December 3, 2005. See note 22(l) to our consolidated financial statements, included under “Item 18. Financial Statements.”

Item 14. Material Modifications to the Rights of Security Holders and Use of Proceeds

Not applicable.

Item 15. Controls and Procedures

Our President and Principal Executive Officer and our Principal Financial Officer have evaluated the effectiveness of the design and operation of the our disclosure controls and procedures (as defined under Rules 13a-15(e) and 15d-15(e) of the Exchange Act) as of December 31, 2003.

Based upon that evaluation, our President and Principal Executive Officer and our Principal Financial Officer observed that there were certain weaknesses in our disclosure controls and procedures and our internal controls that temporarily impacted the timely processing of PDVSA’s operational and financial data. The company’s financial reporting systems continue to suffer delays in the generation and preparation of financial statements. In particular, there were delays in closing the year-end accounting records and in the analysis of accounts. However, PDVSA has commenced a project to meet the requirements of Section 404 of the Sarbanes Oxley Act, regarding the evaluation and improvement of its Financial Internal Control Process.

Therefore, as of the date of this annual report, our management, including our President and Principal Executive Officer and our Principal Financial Officer, have evaluated our disclosure controls and procedures related to the recording, processing, summarization and reporting of information in our periodic reports that we file with the Securities and Exchange Commission (SEC) and concluded that such controls are adequate. These disclosure controls and procedures have been designed to ensure that (a) material information relating to PDVSA, including its consolidated subsidiaries, is made known to our management, including these officers, by other employees of PDVSA and its subsidiaries, and (b) this information is recorded, processed, summarized, evaluated and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Our controls and procedures can only provide reasonable, not absolute, assurance that the above objectives have been met. Also, PDVSA does not control or manage certain of its

unconsolidated entities and as such, the disclosure controls and procedures with respect to such entities are more limited than those it maintains with respect to its consolidated subsidiaries.

PDVSA, aware of its responsibility with the Securities and Exchange Commission concerning compliance with the Sarbanes Oxley Act, has decided to begin the evaluation of the Internal Control System of its Financial Reporting. We hope to complete this task and achieve external auditor’s certification by the beginning of 2007.

We intend to complete this project in order to strengthen even further our Internal Control System and thus, improve the reliability of our financial data available to investors worldwide. Additionally, we consider it an excellent opportunity to upgrade our financial management systems as has been done with other world class corporations.

Item 16. [Reserved]

Item 16A. Audit Committee Financial Expert

Jesús Villanueva serves as the Audit Committee Financial Expert. See “Item 6.A Directors and senior management.”

Item 16B. Code of Ethics

By December 2003 PDVSA had not updated its ethics code. However, by July 15, 2005 the Internal Audit Executive Direction had revised the ethics code, the responsibilities of governance committee and the hot line procedure. These documents are being evaluated by a multidisciplinary team, after which they will be submitted to the Audit Committee and Board of Directors for approval.

Item 16C. Principal Accountant Fees and Services

The following table presents fees for professional audit services rendered by Alcaraz Cabrera Vázquez KPMG LLP and Price Waterhouse LLP for the audit of the Company’s financial statements for the years ended December 31, 2003 and 2002, respectively, and fees billed for other services rendered by those firms during the period they served as auditors for the Company.

	2003		2002
	(000s omitted)

Audit Fees (PDVSA, PDV Europe, Caribbean)	$	1,510	$	2,468
Audit Fees (CITGO)	1,899		1,090
Audit-Related Fees (1)	450		84
Tax Fees (2)	127		157
All Other Fees (3)	0		106
Total	$	3,986	$	3,905

(1) Audit Related Fees include fees related to CITGO’s registration of unsecured senior notes.

(2) Fees related to the preparation of taxes related to our subsidiaries, CITGO, Nynäs, Bitor, and Pequiven.

(3) Fees related mainly to physical inventories and to the evaluation of PDVSA’s export processes.

PART III

Item 17. Financial Statements

We have responded to Item 18 in lieu of this item.

Item 18. Financial Statements

See pages F-1 through F-76 incorporated herein by reference.

The following financial statements, together with the report of Alcaraz Cabrera Vázquez (a member firm of KPMG International) thereon, are filed as a part of this annual report:

		Page

Report of Independent Registered Public Accounting Firm of Alcaraz Cabrera Vázquez (a member firm of KPMG International)		F-1

Independent Auditors’ Report of Deloitte & Touche LLP		F-2

Consolidated Balance Sheets at December 31, 2003 and 2002		F-3

Consolidated Statements of Income for the years ended December 31, 2003, 2002 and 2001		F-4

Consolidated Statements of Stockholder’s Equity and Comprehensive Loss for the years ended December 31, 2003, 2002 and 2001		F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2003, 2002 and 2001		F-6

Notes to Consolidated Financial Statements		F-7

Report of Independent Registered Public Accounting Firm

To the Stockholder and Board of Directors of

Petróleos de Venezuela, S.A. (PDVSA):

We have audited the accompanying consolidated balance sheets of Petróleos de Venezuela, S.A. and subsidiaries (PDVSA) (wholly-owned by the Bolivarian Republic of Venezuela) as of December 31, 2003 and 2002, and the related consolidated statements of income, stockholder’s equity and comprehensive loss, and cash flows for each of the years in the three-year period ended December 31, 2003. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the 2002 and 2001 consolidated financial statements of PDV Holding, Inc. and subsidiaries, a wholly-owned subsidiary, which statements reflect total assets constituting 13% as of December 31, 2002 and total revenues constituting 46% and 43% for the years ended December 31, 2002 and 2001, respectively, of the related consolidated totals. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for PDV Holding, Inc. and subsidiaries for 2002 and 2001, is based solely on the report of the other auditors.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the report of the other auditors provide a reasonable basis for our opinion.

In our opinion, based on our audit and the report of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Petróleos de Venezuela, S.A. and subsidiaries (PDVSA) as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2003, in conformity with accounting principles generally accepted in the United States of America.

ALCARAZ CABRERA VÁZQUEZ

/s/ David Arismendi N.
David Arismendi N.
Public Accountant
C.P.C. Nº 3424
Caracas, Venezuela

September 15, 2005, except for note 22 (k) which is dated October 7, 2005

F-1

INDEPENDENT AUDITORS’ REPORT

To the Board of Directors and Shareholder of
PDV Holding, Inc.:

We have audited the accompanying consolidated balance sheet of PDV Holding, Inc. and subsidiaries (the “Company”) as of December 31, 2002, and the related consolidated statements of income and comprehensive income, shareholder’s equity and cash flows for the years ended December 31, 2002 and 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of PDV Holding, Inc. and subsidiaries at December 31, 2002, and the results of their operations and their cash flows for the years ended December 31, 2002 and 2001, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Tulsa, Oklahoma
April 11, 2003

F-2

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)

(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Balance Sheets

(In millions of U.S. dollars)

	December 31
	2003	2002
Assets
Current assets:
Cash and cash equivalents (note 1(q))	2,938	1,703
Restricted cash (note 4)	961	1,772
Notes and accounts receivable (note 5)	4,955	3,515
Inventories (note 6)	2,382	2,263
Prepaid expenses and other assets	777	930
Deferred income taxes (note 12)	257	476
Total current assets	12,270	10,659

Restricted cash (note 4)	698	1,033
Recoverable value added tax (note 12(d))	2,150	1,933
Investments in non-consolidated investees (note 7)	3,072	2,854
Property, plant and equipment, net (note 8)	34,720	35,871
Deferred income taxes (note 12)	1,049	454
Long-term accounts receivable and other assets (note 9)	1,396	2,135
	55,355	54,939
Liabilities and Stockholder’s Equity
Current liabilities:
Accounts payable to suppliers (note 11)	3,365	2,850
Current portion of long-term debt (note 14)	750	1,817
Income taxes payable (note 12)	624	327
Deferred income taxes (note 12)	28	—
Employee termination, pension and other postretirement benefits (note 16)	263	431
Accrued and other liabilities (note 17)	2,293	1,757
Total current liabilities	7,323	7,182

Long-term debt, net of current portion (note 14)	6,265	6,426
Employee termination, pension and other postretirement benefits (note 16)	1,908	2,395
Deferred income taxes (note 12)	1,066	946
Accrued and other liabilities (note 17)	1,282	588
Total liabilities	17,844	17,537

Minority interests	93	114
Stockholder’s equity	37,418	37,288
	55,355	54,939

The accompanying notes form an integral part of the consolidated financial statements.

F-3

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)

(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Statements of Income

(In millions of U.S. dollars)

	Years ended December 31
	2003		2002	2001
Sales of crude oil and products:
Exports and international markets	44,178		39,875	42,682
In Venezuela	961		1,236	1,701
Petrochemical and other sales	1,071		1,201	1,403
Equity in earnings of non-consolidated investees (note 7)	379		268	464
	46,589		42,580	46,250

Costs and expenses:
Purchases of crude oil and products	21,016		17,956	18,228
Operating expenses	9,338		9,299	10,882
Exploration expenses	27		133	174
Depreciation and depletion (note 8)	2,824		3,038	2,624
Asset impairment (note 8)	296		722	257
Selling, administrative and general expenses	1,479		1,854	1,853
Production and other taxes (note 12)	6,428		5,748	3,760
Financing expenses	627		763	509
Other (income) expenses, net	(8	)	323	199
	42,027		39,836	38,486

Income before income taxes, minority interests and cumulative effect of accounting change	4,562		2,744	7,764
Income taxes (note 12)	1,602		149	3,766
Minority interests	6		5	5

Income before cumulative effect of accounting change	2,954		2,590	3,993

Cumulative effect of accounting change for asset retirement obligations, net of deferred tax benefit of 175 (note 1(n))	234		—	—
Net income	2,720		2,590	3,993

The accompanying notes form an integral part of the consolidated financial statements.

F-4

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)

(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Statements of Stockholder’s Equity and Comprehensive Loss

Years ended December 31, 2003, 2002 and 2001

(In millions of U.S. dollars)

	Capital stock	Legal reserves and other		Accumulated losses		Accumulated other comprehensive loss		Total stockholder’s equity
Balances at December 31, 2000	39,094	8,133		(8,971	)	(324	)	37,932
Comprehensive income:
Net income 2001	—	—		3,993		—		3,993
Change in additional minimum pension liability, net of tax of 110	—	—		—		(53	)	(53	)
Total comprehensive income								3,940

Transfer from reserves	—	(151	)	151		—		—
Cash dividends	—	—		(4,711	)	—		(4,711	)
Non-cash dividends	—	—		(63	)	—		(63	)
Balances at December 31, 2001	39,094	7,982		(9,601	)	(377	)	37,098

Comprehensive income:
Net income 2002	—	—		2,590		—		2,590
Change in additional minimum pension liability, net of tax of 377	—	—		—		352		352
Total comprehensive income								2,942

Transfer to reserves	—	66		(66	)	—		—
Cash dividends	—	—		(2,752	)	—		(2,752	)
Balances at December 31, 2002	39,094	8,048		(9,829	)	(25	)	37,288

Comprehensive income:
Net income 2003	—	—		2,720		—		2,720
Change in additional minimum pension liability, net of nil tax	—	—		—		4		4
Total comprehensive income								2,724

Transfer to reserves	—	328		(328	)	—		—
Cash dividends	—	—		(2,343	)	—		(2,343	)
Non-cash dividends	—	—		(251	)	—		(251	)
Balances at December 31, 2003	39,094	8,376		(10,031	)	(21	)	37,418

The accompanying notes form an integral part of the consolidated financial statements.

F-5

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)

(Wholly-owned by the Bolivarian Republic of Venezuela)

Consolidated Statements of Cash Flows

(In millions of U.S. dollars)

	Years ended December 31
	2003		2002		2001
Cash flows from operating activities:
Net income	2,720		2,590		3,993
Adjustment to reconcile net income to net cash provided by operating activities:
Depreciation and depletion	2,824		3,038		2,624
Asset impairment	296		722		257
Cost of asset retirement obligations	234		—		—
Deferred income taxes	(53	)	(552	)	603
Provision for (reversal of) employee termination, pension and other postretirement benefits	(407	)	1,340		1,479
Equity in earnings of non-consolidated investees	(379	)	(268	)	(464	)
Dividends received from non-consolidated investees	240		228		163
Change in operating assets:
Notes and accounts receivable	(1,691	)	(235	)	1,155
Inventories	(119	)	(55	)	(33	)
Prepaid expenses and other assets	892		374		(554	)
Recoverable value added tax	(217	)	217		(675	)
Change in operating liabilities:
Accounts payable to suppliers	515		(193	)	(500	)
Income taxes payable, accrued and other liabilities and minority interests	1,135		(1,266	)	(323	)
Payments of employee termination, pension and other postretirement benefits	(244	)	(1,060	)	(760	)
Net cash provided by operating activities	5,746		4,880		6,965
Cash flows from investing activities:
Capital expenditures, net	(1,969	)	(2,743	)	(3,781	)
Decrease (increase) in restricted cash	1,146		1,472		(1,666	)
Investments	(79	)	5		184
Net cash used in investing activities	(902	)	(1,266	)	(5,263	)
Cash flows from financing activities:
Proceeds from issuance of debt	962		1,175		1,509
Debt payments	(2,245	)	(1,359	)	(681	)
Dividends paid	(2,326	)	(2,652	)	(4,862	)
Net cash used in financing activities	(3,609	)	(2,836	)	(4,034	)
Net increase (decrease) in cash and cash equivalents	1,235		778		(2,332	)

Cash and cash equivalents at beginning of year	1,703		925		3,257
Cash and cash equivalents at end of year	2,938		1,703		925

SUPPLEMENTAL DISCLOSURE:
Cash paid during the year for:
Interest, net of capitalized amounts	502		615		699
Income taxes	1,315		911		3,443
Non-cash activities:
Tax certificates applied against income taxes payable	—		—		84
Offset of accounts	264		57		—
Payment of dividends using trade notes receivable	251		—		63

The accompanying notes form an integral part of the consolidated financial statements.

F-6

PETRÓLEOS DE VENEZUELA, S.A. AND SUBSIDIARIES (PDVSA)

(Wholly-owned by the Bolivarian Republic of Venezuela)

Notes to Consolidated Financial Statements

December 31, 2003, 2002 and 2001

(1) Operations and Summary of Significant Accounting Policies

(a) Operations

Petróleos de Venezuela, S.A. and its subsidiaries (PDVSA or the Company) are wholly-owned by the Bolivarian Republic of Venezuela, which controls PDVSA through the Ministry of Energy and Petroleum (MEP) (formerly Ministry of Energy and Mines - MEM). PDVSA is responsible for developing the national petroleum, petrochemical, coal and Orimulsión® industries and planning, coordinating, supervising and controlling the activities of its subsidiaries, both in Venezuela and abroad (see note 22 (f)). Most of the foreign companies are responsible for refining and marketing activities in North America, Europe and the Caribbean.

The main activities of PDVSA are governed by the Organic Hydrocarbons Law, which came into effect in January 2002, repealing the Hydrocarbons Law of 1943, the Law of Assets Subject to Reversion in Hydrocarbon Concessions of 1971, the Organic Law that Reserves for the State the Exploitation of the Domestic Market for the Byproducts of Hydrocarbons of 1973, the Organic Law that Reserves for the State the Industry and Trade of Hydrocarbons of 1975, the Organic Law of Domestic Market Opening for Gasoline and Other Hydrocarbon-derived Fuels for Use in Automobiles of 1998, and any other legal provision that may be in conflict with this law. Gas activities are regulated by the Organic Law of Gas Hydrocarbons of September 1999 and its Regulation dated June 2000.

The main changes in the new Organic Hydrocarbons Law which affect the Company are as follows:

• Production tax or royalty increased from 16-2/3% to 30% of the volume of extracted hydrocarbons. For mature reservoirs or extra-heavy crude oil from the Orinoco Belt, the percentage ranges from 20% to 30%, and from 16-2/3% to 30% for Bitumen, based on the profitability of those reservoirs.

• Other taxes:

• Surface tax: equal to 100 tax units for each square kilometer or fraction thereof for each year, determined based on the concession area not under production; with an annual increase of 2% for five years and 5% in subsequent years.

• General consumption tax: applicable to each liter of hydrocarbon-derived product sold in the domestic market, the rate for which shall be fixed annually in the Budget Law at between 30% and 50% of the price paid by the final consumer. For the years 2003 and 2002 the applicable tax rate was 30%.

• Tax on the Company’s own consumption: equivalent to 10% of the value of each cubic meter of hydrocarbon-derived product, produced and consumed as fuel oil in the organization’s operations, calculated based on the final sale price.

F-7

During December 2002 and the first months of 2003, a work stoppage promoted by some sectors disrupted certain activities in the country, including the operations of PDVSA and its Venezuelan subsidiaries. These events affected the production of crude oil and natural gas, as well as the exports of crude oil and by-products (see notes 20 and 21).

As a result of the modifications to PDVSA’s corporate guidelines and in order to support works or services to develop infrastructure and highways and roads, agricultural, health and educational activities and to further productive investments, PDVSA takes part in diverse programs established by the National Government. PDVSA’s participation provides for the contribution of cash to finance social programs and projects, including those denominated “misiones” (see notes 4, 18 and 22(a)).

(b) Basis of Presentation

In preparing its consolidated financial statements, the Company has elected, for international reporting purposes, to present its financial statements in accordance with accounting principles generally accepted in the United States of America (US GAAP). The main economic operating environment of PDVSA consists of the international markets for crude oil and products. The U.S. dollar (dollar or $) is the reporting currency for PDVSA. The dollar is the functional currency of the Company’s subsidiaries in Venezuela and the United States of America.

Assets and liabilities of subsidiaries outside of Venezuela and the United States of America are generally translated into U.S. dollars at the rate of exchange in effect at the balance sheet date. Income and expense items are translated at the weighted average exchange rate prevailing during each year presented. The translation effect is not significant in total and has not been significant in recent years.

Transactions in foreign currencies other than the dollar are converted at the exchange rate in effect at the transaction date. Monetary assets and liabilities denominated in foreign currencies other than the dollar are reported in US dollars at the exchange rate in effect at the balance sheet date and the resulting exchange gains or losses are recognized in the statement of income (see note 3).

(c) Estimates, Risks and Uncertainties

In order to prepare the consolidated financial statements management is required to make estimates that have an effect on the reported amounts of assets and liabilities and the reported amounts of income and expenses during the corresponding period, as well as the disclosures of contingent assets and liabilities at the financial statements dates. The Company uses its best estimates and judgments; however, the final results could vary in relation to the original estimates due to the occurrence of future events.

PDVSA’s operations can be influenced by domestic and international political, legislative, regulatory and legal environments. In addition, significant changes in the prices or availability of crude oil and refined products could have a significant impact on the results of operations for any particular year.

(d) Consolidation

Subsidiaries

Subsidiary companies are those controlled by PDVSA or where the latter has a share greater than 50% of the capital stock. Control exists when PDVSA has the power, directly or indirectly to control the financial and operating policies of an entity in order to obtain benefits based on its

F-8

activities. The potential voting rights that can be exerted or agreed are taken into consideration for purposes of assessing control. The subsidiaries’ financial statements are included from the date of acquiring control until the date control ceases.

Significant wholly-owned subsidiaries are: PDVSA Petróleo, S.A. (PDVSA Petróleo); Petroquímica de Venezuela, S.A. (Pequiven) (see note 22(f)); PDVSA Gas, S.A. (PDVSA Gas); Deltaven, S.A. (Deltaven) and Corporación Venezolana del Petróleo, S.A. (CVP) in Venezuela; PDV Holding, Inc. (PDV Holding) and its main subsidiary PDV America, Inc. (PDV America), which operate in the United States of America and PDVSA Finance Ltd. (PDVSA Finance), a company incorporated in The Cayman Islands and that acts as PDVSA’s corporate financing vehicle. The main activity of PDVSA in the United States of America is represented by CITGO Petroleum Corporation and its subsidiaries (CITGO), which is wholly-owned by PDV America.

Non-Consolidated Investees

Non-consolidated investees are those entities in which PDVSA has significant influence, but not control, over the financial and operating policies or those in which it owns between 20% and 50% of the capital stock. The consolidated financial statements include PDVSA’s share of the recognized gains and losses of non-consolidated investees on an equity basis, from the date when joint control commences until the date when significant control ceases. When PDVSA’s share of losses exceeds the carrying amount of the investment, the carrying amount is reduced to nil and recognition of further losses is discontinued except to the extent that PDVSA has incurred obligations in respect of the investee. Prior to the adoption of Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (SFAS No. 142), the excess of cost of the stock of those investees over PDVSA’s share of their net assets at the acquisition date was recognized as goodwill and was being amortized on a straight-line basis over a maximum of 40 years, based on the estimated useful lives of the investees’ assets. Subsequent to adoption of SFAS No. 142 on January 1, 2002, the equity method goodwill is not amortized but is tested annually for impairment, by applying a fair-value-based test at the reporting unit level. The effect of adopting this standard was not significant.

Transactions Eliminated on Consolidation

Intercompany balances and transactions, and any unrealized gains from intercompany transactions, are eliminated in preparing the consolidated financial statements.

Jointly Controlled Entities

Entities controlled jointly are those where PDVSA has common control, established through a contractual agreement. PDVSA Petróleo participates through its consolidated subsidiaries PDVSA Cerro Negro, S. A. (PDVSA Cerro Negro), PDVSA Sincor, S. A. (PDVSA Sincor) and Corpoguanipa, S. A. (Corpoguanipa), in associations for the development of extra-heavy petroleum reserves in the Orinoco Belt (see note 10(a)). These subsidiaries of PDVSA Petróleo account for these investments using the proportional consolidation method, recognizing their percentage share in the assets, liabilities, income and costs, in accordance with their percentage participation in the joint businesses from the date of acquiring joint control until the date that joint control ceases.

F-9

Investments at Cost

Investments of less than 20% are recorded at cost and dividends from these companies are included in income when declared.

(e) Revenue Recognition

Income from the sale of crude oil, natural gas, refined and petrochemical products, mineral carbon, Orimulsión® and others from the Venezuelan subsidiaries and abroad are recognized in the statement of income when the significant risks and advantages derived from ownership have been transferred to the buyer. This transfer is determined by the delivery terms established in the contract with the client. No income is recognized if there is a significant uncertainty as to the recovery of the obligation acquired by the customer.

(f) Trade Accounts Receivable

Trade accounts receivable are accounted for using the amounts billed and are presented net of an estimated allowance for doubtful accounts, which represents the amount of probable losses. The Company estimates such allowance based on the aging of accounts receivable and the results of assessment of the client portfolio.

(g) Inventories

Inventories are stated at the lower of cost or market value. Costs of inventories of crude oil and its products are determined by the last-in, first-out (LIFO) method. Fertilizers and industrial products are stated at average cost. Materials and supplies are stated mainly at average cost, less an allowance for possible losses, and are classified into three groups: current assets, non-current assets and the portion to be capitalized as property, plant and equipment.

(h) Property, Plant and Equipment

Property, plant and equipment are stated at cost net of accumulated depreciation and losses due to impairment (see note 1(i)). The successful efforts method of accounting is used for oil and gas exploration and production activities. All costs of development wells, related to plant and equipment and oil and gas properties are capitalized. Costs of exploratory wells are capitalized pending determination of whether the wells find proved reserves. Costs of wells for which no proved reserves are found are expensed, when they are determined unsuccessful. Other exploratory expenditures, including the geological and geophysical costs, are expensed as incurred. Major replacements and renewals are capitalized. Expenditures for major maintenance and plant repairs (plant turnaround costs) are recorded as deferred costs and amortized over the period between maintenance. Expenditures for minor maintenance, repairs and renewals carried out to maintain facilities in operating condition are expensed. Income or losses resulting from the withdrawals or disposals of assets are included as operating expenses in the consolidated statement of income.

The costs of properties, plant and equipment also include, when relevant, the amounts associated with obligations for asset disposals (see note 1(n)).

F-10

Financing costs of projects requiring major investments in long-term construction and those incurred from financing of specific projects are capitalized and amortized over the estimated useful lives of the related assets.

Depreciation and depletion of capitalized costs of proved crude oil, natural gas and bitumen production properties are determined using the units-of-production method by field, based on the proved developed reserves. The rates used are reviewed annually based on an analysis of the reserves and applied retroactively at the beginning of the year. Depreciation and depletion for coal production are determined using the units-of-production method, based on the proved reserves, as they are produced. Depreciation of petrochemical plants is determined using the units-of-production method. The capitalized costs of other plants and equipment are depreciated on a straight-line basis over their estimated useful lives, which for refining assets and other facilities range between 17 and 25 years; 20 years for the administrative buildings; 21 years for the extra-heavy crude upgrading assets and between 3 and 10 years for the remaining assets. In addition, the assets acquired under financial leases are depreciated using the straight-line method over approximately 10 years, which approximates the average useful life of such assets, as ownership of these assets is transferred at the end of the lease term.

(i) Impairment of Long-Lived Assets

PDVSA evaluates for impairment the carrying value of long-lived assets whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of the related assets to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated future cash flows, an impairment charge is recognized for the amount by which the carrying amount of the asset exceeds the fair value of the asset. Assets to be disposed of would be separately presented in the balance sheet and reported at the lower of the carrying amount or fair value less costs to sell.

(j) Accounting for Income Taxes

Income taxes are accounted for under the asset and liability method as follows: a) A current tax liability or asset is recognized for the estimated taxes payable or refundable on tax returns for the current year, b) A deferred tax liability or asset is recognized for the estimated future tax effects attributable to temporary differences and tax loss and tax credit carryforwards, c) The measurement of current and deferred tax liabilities and assets is based on provisions of the enacted tax law and the effects of future changes in the tax law or rates are not anticipated, and d) The measurement of deferred tax assets is reduced, if necessary, by the amount of any tax benefits for which available evidence indicates that it is more likely than not that they will not be realized. Under this method, deferred tax is recognized with respect to all temporary differences, and the benefit from utilizing tax loss carryforwards and tax credits is recognized in the year in which the losses or credits arise, subject to a valuation allowance with respect to any tax benefits not expected to be realized.

PDVSA and its Venezuelan subsidiaries were required to adjust the tax bases of their non-monetary assets and liabilities in bolivars for the effects of inflation beginning in 1993. No deferred tax asset is recorded for the future benefit of the inflation revaluation in accordance with SFAS No. 109. SFAS No. 109 prohibits recognition of a deferred tax liability or asset for

F-11

differences related to assets and liabilities that are remeasured from bolivars to U.S. dollars using historical exchange rates and that result from: (1) changes in exchange rates or (2) indexing for tax purposes. Revaluation for the effects of inflation on PDVSA and its Venezuelan subsidiaries’ non-monetary assets and liabilities is performed annually. These annual revaluations may generate additional taxable income or losses which may be offset against or increase the benefit from the amortization of the initial and annual revaluation. Under SFAS No. 109, the net benefit from the initial and future revaluations are recognized as realized. Foreign exchange gains or losses related to deferred taxes are included in deferred tax expense.

(k) Employee Termination, Pension and Other Postretirement Benefits

PDVSA accrues its liability for Venezuelan employee termination benefits, in accordance with Venezuelan labor legislation and the collective labor contracts. A significant portion of the termination benefits has been deposited in trust accounts on behalf of the employees.

In October 2002, PDVSA signed a new collective labor contract effective until 2004, introducing improved salaries and benefits for its contractual workers (see note 22 (e)).

Labor contracts, both in Venezuela and abroad, provide for pension plans for all eligible workers based, among other things, on length of service, age and compensation levels. The pension liability, that is calculated using actuarial methods, establishes an individual capitalization plan for each worker, with monthly contributions. The cost of this program is being funded currently.

PDVSA provides other benefits to its eligible former employees, such as health care, life insurance, disability payments, payments in lieu of salaries and wages and other social benefits. This liability is accrued using actuarial methods over the active service lives of employees. The net periodic costs are recognized as employees render the services necessary to earn the postretirement benefits.

(l) Environmental Expenditures

Pursuant to the environmental policy established by PDVSA and the applicable legal standards a liability is recognized when the costs are probable and may be reasonably estimated. Disbursements relating to environmental preservation, linked to income due to current or future operations are recorded as expenses or assets, as required. The outlays relating to past operations and that do not contribute to the obtaining of current or future income are charged to expenses. The creation of these allowances coincides with the identification of an environmental remedial obligation for which the Company has adequate information available to determine a reasonable estimate of the cost of remediation. Subsequent adjustments to estimates, when necessary, may be recorded upon obtaining additional information.

(m) Commodity and Interest Rate Derivatives

The Company uses derivative financial instruments to reduce its exposure to commodity price risk and interest rate risk arising from operational, financing and investment activities. In accordance with its treasury policy, PDVSA does not use derivative financial instruments for trading or speculative purposes.

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PDVSA elected not to designate any of its derivatives as hedges for accounting purposes, except under limited circumstances involving derivatives with initial terms of 90 days or greater and notional amounts of $25 million or greater. There were no derivative instruments accounted for as hedges outstanding at December 31, 2003 or 2002. Derivative financial instruments are recognized initially at cost. Subsequent to initial recognition, derivative financial instruments are stated at fair value and subsequent changes are recognized in the consolidated statement of income. The effects of changes in the fair value of derivatives during the years ended December 31, 2003, 2002 and 2001 are recorded in other income (expenses), net and were not significant.

The fair value of future purchase-sale contracts of petroleum is their quoted market price at the balance sheet date, which is the present value of the quoted future price.

The fair value of interest rate swaps, to manage fluctuations in cash flows resulting from interest rate risk, is the estimated amount that would be obtained or paid by PDVSA in order to make the operation effective at the financial statements date, considering current interest rates and the current solvency of the counterparties.

(n) Costs Related to Asset Retirement Obligations

The Company provides for estimated dismantlement and site removal costs of oil and gas exploration and production areas and other industrial facilities based on the plan of retirement of the related assets in the future. Effective January 1, 2003, the Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations” which addresses financial accounting and reporting for obligations associated with the retirement of tangible long-lived assets and the associated asset retirement costs. It applies to legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of such assets. It requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of such fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset and this additional carrying amount is depreciated over the life of such asset. The liability is adjusted at the end of each period to reflect the passage of time and changes in the estimated future cash flows underlying the initial fair value measurement, and such adjustments are reflected in the consolidated statement of income. If PDVSA’s obligation is settled for other than the carrying amount of the liability, PDVSA will recognize a gain or loss on settlement.

During 2003, the Company performed an analysis of the costs associated with obligations for asset disposals relating to production and injection wells, which were recognized in the financial statements of that year as follows:

• $234 million corresponding to the cumulative effect of the cost associated with obligations due to asset disposals, net of the deferred income tax benefit of $175 million, which is presented in the consolidated statement of income.

• $65 million capitalized as part of property, plant and equipment associated with these obligations, net of $60 million of accumulated depreciation (see note 8).

• $537 million corresponding to liabilities associated with obligations for asset disposals, presented in accrued and other liabilities (see note 17).

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• $6 million of depreciation expense on assets associated with obligations from asset disposals.

• $57 million of financial expense corresponding to the adjustment to this obligation from January 1, 2003 to December 31, 2003.

The asset retirement obligations relating to the refining and marketing plants and related assets were not estimated as these assets are considered to have an indeterminate life, due to planned major maintenance and repairs, and therefore there is not sufficient information available to determine within a reasonable range an estimate of the related asset retirement obligation.

The following table indicates movements of the Company’s asset retirement obligations for 2003, 2002 and 2001, and illustrates the effects on the consolidated financial position had FAS 143 been applied retroactively (in millions of dollars):

	2003		2002		From January 1, 1924 to December 31, 2001
Accrual for asset retirement obligations as of January 1	478		429		117
Accretion	57		51		312
Acquisitions	3		5		—
Sales and disposals	(1	)	(7	)	—
Accrual for asset retirement obligations as of December 31	537		478		429

Property, plant and equipment as of January 1	122		117		—
Acquisitions	3		6		117
Sales and disposal	—		(1	)	—
Property, plant and equipment as of December 31	125		122		117

Accumulated depreciation and depletion as of January 1	54		47		—
Depreciation and depletion	6		7		47
Accumulated depreciation and depletion as of December 31	60		54		47

(o) Research and Development Costs

Research and development costs are expensed when incurred. In 2003, 2002 and 2001, amounts charged to expense for research and development activities amounted to $13 million, $31 million and $41 million, respectively.

(p) Segment Information

A segment is an identifiable component of PDVSA that is engaged in supplying products or services (operating segment), or that engages into providing products or services within a particular economic environment (geographical segment), that is subject to specific and diverse risks and benefits of other segments.

PDVSA has determined that its reportable segments are those that are based on the Company’s method of internal reporting. PDVSA identifies such segments based on its business units and

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geographically. PDVSA’s reportable operating segments include exploration, production and improvement of crude oil and natural gas (upstream); refining, supply and marketing (downstream); and petrochemicals.

(q) Cash and Cash Equivalents

For purposes of the consolidated statement of cash flows, PDVSA considers as cash equivalents all deposits and other cash placements with original maturities of less than three months, including amounts deposited with the Central Bank of Venezuela (BCV), available on a current basis, which at December 31, 2003, 2002 and 2001 amounted to $1,059 million, $273 million and $87 million, respectively.

(r) Reclassifications

Certain reclassifications have been made to the 2002 and 2001 financial statements to conform to the classifications used in 2003.

(s) Recently Issued Accounting Standards

Some important accounting standards recently issued are summarized as follow (see note 22(j)):

In December 2003, the FASB issued FASB Interpretation No. 46 (revised December 2003), Consolidation of Variable Interest Entities, which addresses how a business enterprise should evaluate whether it has a controlling financial interest in an entity through means other than voting rights and accordingly should consolidate the entity. The Company applies FIN 46R to variable interests in VIEs created after December 31, 2003. For variable interests in VIEs created before January 1, 2004, the Interpretation will be applied beginning on January 1, 2005. For any VIEs that must be consolidated under FIN 46R that were created before January 1, 2004, the assets, liabilities and noncontrolling interests of the VIE initially would be measured at their carrying amounts with any difference between the net amount added to the balance sheet and any previously recognized interest being recognized as the cumulative effect of an accounting change. If determining the carrying amounts is not practicable, fair value at the date FIN 46R first applies may be used to measure the assets, liabilities and noncontrolling interest of the VIE. The Company expects that the adoption of FIN 46R will not have a material impact on its consolidated financial position or results of operations.

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(2) Foreign Exchange Agreement with the Central Bank of Venezuela (BCV)

Under Venezuelan law, the Central Bank of Venezuela (BCV) is required to sell foreign currency to PDVSA at an agreed rate effective at the transaction date, which approximates the market rate, and on a priority basis to meet its foreign exchange needs, as set out in PDVSA’s annual foreign exchange budget. Pursuant to the agreement between the Venezuelan government and the BCV, all foreign currency from petroleum activities received by PDVSA, including its Venezuelan subsidiaries, must be sold to the BCV at the agreed rate, which approximates the market rate. PDVSA may use such foreign currency to service its current debt, make capital investments and pay operating expenses and maintain a rotatory fund for working capital which shall not exceed $600 million (see notes 4 and 22(a)).

On February 5, 2003, the Venezuelan Government established an exchange control regime and fixed the exchange rates for the sale and purchase of foreign currency at Bs1,600.00 to $1 and Bs1,596.00 to $1, respectively. It also created the Comisión para la Administración de Divisas (CADIVI) (Foreign Currency Administration Commission) setting forth rules for the administration and control of foreign currencies. Despite the new regime, the exchange agreement between the Ministry of Finance and the BCV contains provisions that are specific to PDVSA, which have been in effect since 1982. Among other things, the exchange regime exempts PDVSA from the exchange controls referred to above, up to the limit of the rotatory fund. As a result, the new exchange controls do not have a significant impact on PDVSA’s operations (see notes 3, 22(b) and 22(i)).

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(3) Transactions and Balances in Currencies Other Than the Dollar

PDVSA has the following monetary assets and liabilities denominated in currencies other than the dollar which are converted to dollars at the exchange rate prevailing at the balance sheet date (in millions of dollars):

	December 31
	2003	2002
Monetary assets:
Bolivars	6,260	6,495
Euros	52	195
Other currencies	78	5
	6,390	6,695

Monetary liabilities:
Bolivars	4,459	5,272
Euros	150	172
Other currencies	320	414
	4,929	5,858
Net monetary asset position (see note 22(b))	1,461	837

The year-end exchange rate, the average exchange rate for the year and the interannual increases in the exchange rate and Consumer Price Index (CPI), published by the BCV, were as follows:

	December 31
	2003	2002	2001
Exchange rates at year-end (Bs/$1)	1,600.00	1,403.00	770.09
Average annual exchange rates (Bs/$1)	1,611.32	1,163.91	772.01
Interannual increase in the exchange rate (%)	14.04	82.19	10.29
Interannual increase in the CPI (%)	27.10	31.22	12.29

Net gains from transactions in currencies other than the dollar in 2003 amounted to $266 million, which is comprised of $284 million of gains included in other (income) expenses net, and $18 million loss, included in deferred income tax (benefit) expense. Foreign currency losses in 2002 amounted to $509 million, which are comprised of $26 million gain included in other (income) expenses, net and $535 million of losses included in deferred income tax (benefit) expense. For 2001, gains and losses from currencies other than the dollar were not significant.

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(4) Restricted Cash

Restricted cash includes (in millions of dollars):

	December 31
	2003	2002
Macroeconomic Stabilization Fund (FEM), formerly Macroeconomic Stabilization Investment Fund (FIEM) (see note 18)	698	2,382
Funds for extra-heavy crude oil project in the Orinoco Belt	486	239
Liquidity account of PDVSA Finance	166	161
Trust in Banco de Desarrollo Económico y Social de Venezuela (BANDES) for social programs and projects (see note 22(a))	302	—
Other	7	23
	1,659	2,805
Less current portion	961	1,772
Long-term portion	698	1,033

Macroeconomic Stabilization Fund (FEM)

During November 2003, the Venezuelan Government established the FEM upon termination of the FIEM’s operations, which was created in June 1999, in order to achieve stabilization of the Nation’s expenses, at state and municipal levels. It was constituted to manage the fluctuations of extraordinary income and to which contributions will be made on the basis of additional oil income, the net income corresponding to the Republic, as a consequence of the privatization of public companies or concessions or strategic associations, that have not been employed in operations linked to the management of public liabilities, the extraordinary contributions made by the National Government, other than those stated above and the net yields obtained from operations. PDVSA will contribute 50% of the difference in excess between the income due to oil and byproducts exports in dollars and the average of such income collected during the last three calendar years, after deducting the taxes related to such income.

The deposits made in the FEM may be used in the event of a decrease in the fiscal income from petroleum or in the income from oil and byproducts exports in relation to the average of such income collected during the last three calendar years or in the event of a national state of emergency. In these cases, PDVSA will be able to withdraw an amount that will not exceed 75% of the difference between the estimated income for this period and the average of such income collected during the last three calendar years, with prior approval of the Board of Directors of the FEM and the opinion of the Permanent Finance Commission of the National Assembly. Also, a maximum resources accrual level is established for PDVSA consisting of 30% of the average oil exports during the last three years. In the event of an excess, it will be transferred to the Fondo de Ahorro Intergeneracional. However, if PDVSA is required to execute special investment plans for the management and expansion of its operations, it may use part of such excess, with prior approval of the Stockholder’s Assembly.

F-18

Through the BCV, the National Government transferred the balance available from the FIEM to the FEM of $698 million upon termination of the FIEM and creation of the FEM.

In October 2001 and 2002, and January and April 2003, the Venezuelan Government introduced reforms to the FIEM Law and, among other changes, suspended contributions for the last quarter of 2001 and the years 2002 and 2003.

In June 2002, the board of directors of the FIEM and the National Assembly authorized PDVSA to withdraw up to $2,445 million. As of December 31, 2002, $2,173 million had been withdrawn.

During 2003, the National Government and the National Assembly authorized PDVSA to withdraw $1,430 million from the funds deposited in the FIEM. These funds have been totally utilized by PDVSA as of December 31, 2003.

Funds for Extra-heavy Crude Oil Projects in the Orinoco Belt

The funds for the extra-heavy crude oil projects in the Orinoco Belt correspond to restricted cash that cannot be utilized in the operations of the subsidiary of PDVSA Petróleo. The funds, deposited mainly in current accounts in financial institutions abroad, are restricted in order to comply with commitments related to the financing received for the development of these projects.

Liquidity Account of PDVSA Finance

The restricted cash of the subsidiary PDVSA Finance corresponds to the “Liquidity Account”, in accordance with the agreement signed with financial institutions for the issue of bonds, and which is comprised of cash and time deposits that are permitted investments, including interest earned on such amounts (see note 22 (c)).

Trust with BANDES

As part of the support to the different social programs established by the National Government, on August 21, 2003, the subsidiary CVP and BANDES subscribed a trust agreement, the objective of which is the administration and investment of the fiduciary fund in operations, adjusted to liquidity, safety and profitability principles. Such fiduciary fund was created to fulfill the commitments of CVP to make loans to institutions for the execution and development of housing and infrastructure programs and projects. The trust fund, approved at the Board of Directors’ meeting on August 25, 2003 was created in dollars, with an amount of $300 million, for a duration of one year, extendable automatically for similar periods. As of December 31, 2003 funds held by the trust amounted to $300 million and financial income was generated thereon of $2 million (see note 22(a)).

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(5) Notes and Accounts Receivable

Notes and accounts receivable are summarized as follows (in millions of dollars):

	December 31
	2003	2002
Trade	4,223	3,066
Related parties (see note 18)	436	328
Other	421	179
	5,080	3,573
Less allowance for doubtful trade accounts receivable	125	58
	4,955	3,515

(6) Inventories

Inventories are summarized as follows (in millions of dollars):

	December 31
	2003	2002
Crude oil and products	1,952	1,883
Fertilizers, industrial products, coal, Orimulsion® and other	50	57
Materials and supplies	461	404
	2,463	2,344
Less materials and supplies classified in non-current assets, net (see note 9)	81	81
	2,382	2,263

At December 31, 2003 and 2002, crude oil and products inventories stated using the LIFO method accounted for 79% and 80% of total inventories, respectively.

At December 31, 2003 and 2002, the replacement cost of inventories of crude oil and products exceeded LIFO cost by approximately $1,434 million and $1,759 million, respectively, and accordingly, no write-down was necessary.

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(7) Investments in Non-Consolidated Investees

Investments in non-consolidated investees accounted by the equity method are summarized as follows (in millions of dollars):

	December 31
	Percentage of
	capital stock		Share of equity
	2003	2002	2003	2002
Foreign investees:
United States of America:
CITGO investees:
LYONDELL-CITCO Refining Company, L.P. (LYONDELL-CITCO)	41	41	455	518
The Needle Coker Co. (Needle Coker)	25	25	18	19
Other	—	—	174	179
Chalmette Refining, L.L.C. (Chalmette Refining)	50	50	254	253
Merey Sweeny, L.P. (Merey Sweeny)	50	50	19	14
			920	983
Virgin Islands:
Hovensa L.L.C. (Hovensa)	50	50	888	762
Germany:
Ruhr Oel GmbH (Ruhr)	50	50	172	146
Sweden:
AB Nynäs Petroleum (Nynäs)	50	50	103	83
Colombia:
Monómeros Colombo Venezolanos (Monómeros)	47	47	29	26
Other:
Bitor investees	50	50	4	(3	)
			2,116	1,997
Investees in Venezuela:
Petrolera Zuata, C.A. (Petrozuata)	50	50	419	352
Fertilizantes Nitrogenados de Venezueala, C.E.C. (Fertinitro)	35	35	144	121
Metanol de Oriente, S.A. (METOR)	38	38	110	109
Carbones del Guasare, S.A., subsidiary of Carbones del Zulia, S.A. (CARBOZULIA) (see note 22(f))	49	49	76	53
Supermetanol, C.A.	35	35	64	58
Super Octanos C.A.	49	49	101	97
Ceras de Venezuela, C.A. (Ceraven)	49	49	10	10
Propilenos de Falcón, C.A. (Profalca)	35	35	14	13
Informática Telecomunicaciones, S.A. (Intesa) (see notes 18 and 20)	40	40	—	—
Tripoliven, C.A.	33	33	6	5
Aguas Industriales de Jose, C.A.	25	25	11	10
Other	—	—	1	29
			956	857
Total non-consolidated investees			3,072	2,854

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The carrying value of these investments exceeded PDVSA’s equity in the underlying net assets by approximately $125 million and $197 million at December 31, 2003 and 2002, respectively.

Information on PDVSA’s investments in non-consolidated investees follows (in millions of dollars):

	December 31
	2003	2002
PDVSA’s investments in non-consolidated investees (see note 18)	3,072	2,854
PDVSA’s equity in net income of non-consolidated investees	379	268
Dividends and distributions received from non-consolidated investees	240	228
Investments, including exchange effects	79	5

Summarized gross combined financial information of the above non-consolidated investees abroad and in Venezuela follows (in millions of dollars):

	December 31
	2003						2002
	Venezuela		Abroad		Total		Venezuela		Abroad		Total
Financial position:
Current assets	844		2,641		3,485		851		2,092		2,943
Non-current assets	4,846		7,266		12,112		5,027		7,247		12,274
Current liabilities	(547	)	(1,998	)	(2,545	)	(519	)	(1,886	)	(2,405	)
Long-term liabilities	(2,920	)	(4,504	)	(7,424	)	(3,516	)	(4,400	)	(7,916	)
Net equity	2,223		3,405		5,628		1,843		3,053		4,896

Operating results for the year:
Revenues	1,559		16,142		17,701		1,614		8,913		10,527
Operating income	598		1,360		1,958		548		2,018		2,566
Net income	294		798		1,092		508		246		754

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(8) Property, Plant and Equipment, Net

Property, plant and equipment, net are summarized as follows (in millions of dollars):

	December 31
	2003	2002
Oil and gas production	42,880	40,774
Refining, marketing and transportation	25,075	24,363
Petrochemical	3,353	3,343
Other	1,386	1,343
	72,694	69,823
Less accumulated depreciation and depletion	42,142	39,329
	30,552	30,494
Land	350	355
Construction in progress	3,818	5,022
	34,720	35,871

Depreciation and depletion expenses, impairment charges, asset retirement obligations and capitalized interest are summarized as follows (in millions of dollars):

	December 31
	2003	2002	2001
Depreciation and depletion	2,824	3,038	2,624
Impairment charges	296	722	257
Asset retirement obligations (see note 17)	537	—	—
Capitalized interest	40	51	51

Asset impairment charges relate mainly to oil and gas wells which are planned to be abandoned and retired. For segment reporting purposes these assets are reflected in the Company’s Venezuelan upstream operations.

As of December 31, 2003, PDVSA maintains several projects under execution, included in construction in progress and that will be capitalized as property, plant and equipment at the date of incorporation into operations. The most significant are:

(a) Hamaca Project: includes the participation of third party investors to develop, over a 35-year period, the production, transportation and improvement activities of extra-heavy crude from the Orinoco Belt. As of December 31, 2003, the balance of the investment is approximately $571 million, corresponding to the participation of the Company in this project (see note 10(a)).

(b) The Valorización de Corrientes (VALCOR) Project, executed by PDVSA in the facilities of the Refinery in Puerto la Cruz, Anzoátegui State, is intended to improve the refined products and increase the refining margin, by maximizing the benefit of the existing facilities of industrial services and external areas; this will be accomplished through conditioning the refinery’s facilities

F-23

to produce unleaded gasoline in the country’s eastern region, as well as the production of diesel with low sulphur content. Also, it provides for conditioning the refinery to capture new markets abroad as well as the improvement of air quality. As of December 31, 2003, approximately $487 million has been invested, which is pending capitalization.

(c) The Gas Project of the Plataforma Deltana includes the participation of third parties to complete the exploration and future development of the area. PDVSA completed the project’s initial phase, including 3D seismic analyses and the drilling of four exploratory wells that culminated in May, 2003. At December 31, 2003, approximately $135 million has been invested (see note 10(d)).

(d) The purpose of the Anaco Gas Project is to increase the production of gas to satisfy internal demand. Currently, the drilling process of exploratory wells located north of Anaco, Anzoátegui State is underway. This project includes the design and construction of facilities to increase the daily gas production to 2,400 million cubic feet per day (MMCFD) and 35 thousand barrels per day (MBPD) of light crude. The production capacity of this project is expected to reach 2,400 MMCFD by 2007. The total estimated investment in this project is $732 million and as of December 31, 2003 approximately $39 million has been invested.

(e) Construction and operation of a natural bitumen production and emulsification unit for the production of Orimulsión® (MPE-3). As of December 31, 2003, approximately $31 million has been invested in this project (see note 10(e)).

(f) The main purpose of the Integral Ceuta-Tomoporo project is to maximize the recoverable crude oil reserves value of Ceuta-Tomoporo, through exploitation of the B-superior Eocene formation, which has estimated reserves of 1,000 million barrels of 23.6 °API crude oil. Total investment costs will be approximately $1,200 million, with an average crude oil production of 90 to 277 MBPD. As of December 31, 2003, approximately $28 million has been invested and it is estimated that the development project relating to these reserves will end in 2021.

(g) The Project Mariscal Sucre for Liquefied Natural Gas (LNG) is intended to develop and exploit the reserves of non-associated offshore gas, as well as the construction of a liquefied natural gas plant, for projected gas production of 1,070 MMCFD and the processing of 4.7 million metric tons per year (MMT/Y) of LNG; 300 MMCFD of methane gas that will be used to satisfy the domestic market’s demand, and the remainder of the production is expected to be exported. The LNG exports will be directed towards the eastern coast of the United States of America. The investment required for the development of offshore fields, the LNG plant and the associated infrastructure is estimated to total $2,700 million. As of December 31, 2003, approximately $7 million has been invested.

(h) The purpose of the project Interconexión Oriente-Occidente (East-West Interconnection-ICO-Project) is to connect the natural gas transmission systems of the central and eastern region of Venezuela (Anaco, Anzóategui State-Barquisimeto, Lara State) with the transmission system located in the country’s western region (Ulé-Amuay, Falcón State) in order to cover the gas demand of the country’s western region, expand the gas service to other regions nationwide and to promote the industrial and commercial development in areas near the construction of this transmission system. The estimated total investment in this project is $413 million and it is

F-24

expected to be completed by 2007. As of December 31, 2003, approximately $6 million has been invested.

At December 31, 2003 and 2002, there are certain gas compression plants and related equipment acquired under capital lease agreements recorded as property, plant and equipment for approximately $105 million and $304 million, net of accumulated depreciation of approximately $166 million and $582 million, respectively. Depreciation expense recorded in 2003, 2002 and 2001 for assets acquired under capital lease agreements, amounted to $14 million, $45 million and $45 million, respectively. At December 31, 2003, future lease payments for operating and capital leases are summarized as follows (in millions of dollars):

	Leases
Years	Operating	Capital
2004	311	25
2005	267	6
2006	248	6
2007	227	6
2008	221	6
Remaining years	234	11
Estimated future lease payments	1,508	60
Less interest		(14	)
Present value, included in accrued and other liabilities (see note 17)		46

Rent expense incurred from operating leases during 2003, 2002 and 2001 was $281 million, $182 million and $108 million, respectively.

On August 14, 2001, a fire occurred in the crude oil distilling unit at the Lemont Refinery, Illinois State, United States of America. In May 2002, a new crude distilling unit was available for operations. On September 21, 2001, a fire occurred in the hydrocarbons unit at the Lake Charles refinery, Louisiana State, United States of America. The operations of the hydrocracker unit were resumed on November 22, 2001. The Company recognizes as income, insurance company indemnifications for material damages to its properties, equivalent to the value of such indemnifications in excess of the carrying value of the assets involved in the accident, and recognizes insurance recoveries due to business operations disruption when these amounts are considered realized. During 2003 and 2002, the Company recorded in other (income) expenses, net, $146 million and $407 million, respectively, for recoveries mainly relating to these fires.

F-25

(9) Long-Term Accounts Receivable and Other Assets

Long-term accounts receivable and other assets are summarized as follows (in millions of dollars):

	December 31
	2003	2002
Long-term accounts receivable (see note 18)	680	669
Materials and supplies (see note 6)	81	81
Plant turnaround costs, net of amortization and short-term portion	372	402
Goodwill (see note 7)	52	52
Intangible pension plan asset (see note 16)	40	680
Others	171	251
	1,396	2,135

(10) Joint Development Activities

PDVSA has undertaken the following joint development activities in Venezuela:

(a) Development of the Orinoco Belt Extra-Heavy Crude Oil Reserves

The Venezuelan National Assembly (formerly National Congress) approved between 1993 and 1999 several association agreements for the exploitation and upgrading of extra-heavy crude oil and marketing of the upgraded crude oil, as follows:

	PDVSA’s		Estimated	Total Project
	percentage		gross	Incurred as	Incurred as of
	of		project cost	of December 31,	December 31,
Association	participation	Partners	(unaudited)	2003 (unaudited)	2002 (unaudited)
Petrozuata	49.90	ConocoPhillips	3,085	3,478	3,478
Cerro Negro	41.67	ExxonMobil-BP	2,018	2,823	2,823
Sincor	38.00	Total Fina – Statoil	4,260	4,185	4,185
Hamaca (see note 8)	30.00	ChevronTexaco - ConocoPhillips	3,534	2,544	2,227

The variation between the estimated gross project cost and the cost incurred as of December 31, 2003, in Petrozuata, corresponds mainly to the following factors: a) a change in the scope of the project, which was expanded for the construction of maritime facilities and a terminal for handling solids; b) an increase in the labor cost arising as a result of contractual agreements; and c) an increase in the investment to accelerate the drilling program. The variation between the estimated gross project cost and the cost incurred as of December 31, 2003, in Cerro Negro, corresponds mainly to the operating costs, as well as other additional administrative expenses incurred during the project’s early production stage.

PDVSA Petróleo, participates in these joint ventures through non-consolidated investees: Petrozuata, and its wholly-owned subsidiaries, PDVSA Cerro Negro, PDVSA Sincor and Corpoguanipa (Hamaca Project) (see notes 1(d), 4 and 7).

F-26

The objective of these joint ventures is to perform vertically integrated activities for the exploration, development, production, mixing and transport of extra-heavy crude oil, in the areas of Zuata, Cerro Negro, and Hamaca from the Orinoco Belt, for processing in the improvement plants to produce upgraded crude oil of high gravity for commercialization on the international markets. During the construction phase of the plants, the joint ventures produce development product.

During 1998, 1999, 2000 and 2001, development production commenced in Petrozuata, Cerro Negro, Sincor and Hamaca, respectively. The commercial production of upgraded crude oil in Petrozuata, Cerro Negro, Sincor and Hamaca began in February 2001, August 2001, March 2002 and October 2004, respectively.

The disbursements required for these joint ventures are covered by capital contributions of PDVSA and the partners, from financing and income from development production (see note 14).

During 2001, the Petrozuata and Cerro Negro projects were completed. During 2002 and 2004, the Sincor and Hamaca projects were completed, respectively.

A summary of the combined financial statements of the Cerro Negro, Sincor and Hamaca projects follows (in millions of dollars):

	December 31
	2003		2002
Financial position:
Current assets	862		622
Non-current assets	9,011		8,538
Current liabilities	(596	)	(491	)
Long-term liabilities	(3,544	)	(4,447	)

Net equity	5,733		4,222

Operating results for the year:
Revenues	1,840		1,006
Operating income	1,186		286
Net income	998		195

(b) Association Agreements in New Areas

CVP is the subsidiary that was designated in January 1996 by the MEP, to contract risk and profit sharing agreements with private investor companies (association agreements) to coordinate, control and supervise the activities relating to the exploration and exploitation of hydrocarbon fields in new areas.

F-27

The association agreements provide for the creation of a Control Committee, as the ultimate body for approval and control, which makes the fundamental decisions in the national interest for the Venezuelan Government, in connection with the execution of these association agreements.

These areas were assigned by means of a competitive bid process to participate in association agreements with CVP. These agreements establish that investors will carry out exploration activities at risk, and in those cases where a field is declared commercially viable and a development plan is approved by the Control Committee, CVP will notify the investors of its participation in such development. The participation of CVP shall not be less than 1% or greater than 35%. Considering the exploration, development and commercial production phases of the areas and their potential extension, the agreements, in general, will have a maximum duration of thirty-nine years.

During the reorganization process, initiated by PDVSA’s Board of Directors in 2003, it was decided to transfer to the subsidiary CVP the coordination of activities relating to the operating agreements of the first, second and third rounds and the strategic associations for the exploitation and production of extra-heavy crude of the Orinoco Belt, which were formerly coordinated by the subsidiary PDVSA Petróleo.

In accordance with the terms of the association agreements, CVP and the investors incorporated jointly owned companies for each area, the capital stock of which is represented by 35% Class ”A” shares owned by CVP and 65% Class ”B” shares owned by the investors. The purpose of the jointly owned companies is to direct, coordinate and supervise the activities that will be executed by the operators of the areas.

As of December 31, 2003 and 2002, CVP has investments in shares representing its 35% participation in the companies as of that date, as listed below by area:

Areas	CVP Partners	Jointly owned Companies

Eastern Paria Gulf	Ineparia - ConocoPhillips - ENI B.V. – OPIC Karimun Corp.	Administradora del Golfo de Paria Este, S.A.
Western Paria Gulf (1)	ConocoPhillips - ENI B.V. – OPIC Karimun Corp.	Compañía Agua Plana, S.A.
La Ceiba	Exxon Mobil - PetroCanada	Adminstradora Petrolera La Ceiba, C.A.
San Carlos(2)	Petrobrás Energía de Venezuela, S.A.	Compañía Anónima Mixta San Carlos, S.A.

F-28

(1) Profit sharing agreement under phase I (development)

(2) Changed to a gas license in 2002

The companies listed above have not begun hydrocarbon commercial production operations; the activities performed during 2003 and 2002 consisted mainly of completing the minimum exploratory program and continuation of the exploration efforts, as well as approving and continuing with the assessment and outline plans. These activities included, among others, the reprocessing and 3D and 2D seismic interpretation, as well as the drilling of exploratory/outlining wells. In addition, the Control Committee approved the assessment plan of the discovery in La Ceiba (blocks 1, 3, 4 and 7).

During 2002, the outline and development plan (blocks 5, 6, 9 and 10) of the gas discovery in La Doncella, located in San Carlos, Cojedes State, continued and the MEP granted a gas license for this area. In addition, during 2003, CVP granted the coordination of the area of San Carlos to the MEP and the Ente Nacional de Gas (ENAGAS) and began the liquidation of Compañía Anónima Mixta San Carlos, S. A.

During 2002, no activities in the Eastern Paria Gulf were carried out. In September 2003, upon approval of CVP, Ineparia sold and transferred 75% of its shares in the association agreement for this area as well as its participation in Administradora del Golfo de Paria Este, S. A., to the investors ConocoPhillips (37.5%), ENI B. V. (30.0%), OPIC Karimun Corp (7.5%).

In 2002, the assessment plan approved for blocks 7 and 9 of the Western Paria Gulf continued and an extended test was conducted. In April 2003, the Control Committee declared commercially viable a discovery in the Western Paria Gulf Project, named Corocoro. In May 2003, PDVSA’s Board of Directors authorized CVP to participate in the development plan of this discovery. The participants in the consortium for this development plan for Corocoro are: CVP (35%), ConocoPhillips (32.5%), ENI B.V.(26.0%) and OPIC (6.5%). The plan establishes a total investment of $557 million for the period 2003-2005, and an average production of 60 (MBPD) of crude 24° API, similar to the crude of Tía Juana, until reaching 120 (MBPD) in 2008. Phase II that will be implemented in 2008 provides for an approximate investment of $487 million.

At December 31, 2003 and 2002, the execution status (unaudited) of the modified minimum work program follows:

	Commitment		Execution
	2003	2002	2003	2002
Seismic 2D (Km)	4,670	4,670	4,265	4,265
Seismic 3D (Km²)	2,439	2,439	3,368	3,368
Drilling (wells)	21	21	15	15

F-29

In order to guarantee compliance with the minimum work program established in the agreements, CVP received in July 1996 letters of credit or guarantees from the investors’ parent companies. Pursuant to the agreements, these guarantees may be reduced every six months, upon request of the investors and in accordance with the development of such program. As of December 31, 2003 and 2002, the amount of the guarantees was approximately $29 million for each year and the minimum work programs of Phase I of Exploration were completed.

(c) Operating Agreements

During 1992 and 1993, PDVSA signed, through its subsidiary PDVSA Petróleo, the first and second rounds of operating agreements with specialized international companies. The purpose of these agreements is the reactivation and operation of 15 oil fields which in general cover a term of 20 years. During 2003 and 2002, these reactivated fields have been productive.

In June 1997, PDVSA Petróleo held a third bidding round and awarded an additional 18 fields to be operated under operating agreements with specialized national and international companies. These fields are located in the Venezuelan States of Anzoátegui, Falcón, Monagas and Zulia. Field operations are subject to the approval of development programs which include the execution of exploration activities at the operator’s risk, and in areas where reserves are discovered, the agreement provides for the signing of new agreements for further development. During 2003 and 2002, these reactivated fields have been productive. Since the beginning of the agreements for the third round exploration activities in these fields have not been successful, although such activities continue.

As established in the operating agreements, the investors will make capital investments in the assets necessary to increase production in the fields received, possibly recovering their investments by collecting operating fees and stipends, which are determined based on the amount of crude oil delivered to PDVSA Petróleo during the term of the agreement, at the end of which PDVSA Petróleo has no liability to pay for the remaining value of the assets existing in the fields.

The operating fees, capital fees and other, and stipends included as operating expenses in the consolidated statements of income are presented below (in millions of dollars):

	Years ended
	December 31
	2003	2002	2001
Operating fees	959	852	766
Capital fees and other	638	629	550
Stipends	748	620	794
	2,345	2,101	2,110

As of December 31, 2003 and 2002, the accounts payable related to operating agreements amounted to $614 and $466, respectively, as a result of these operations (see note 11).

F-30

As of December 31, 2003, the investments of these operators, which could be paid back to them by PDVSA Petróleo on the basis of the crude oil to be received together with other facts, amount to approximately $7,923 million, which relate to productive fields.

(d) Plataforma Deltana

For purposes of granting rights related to the exploration and development of the Plataforma Deltana (Delta Platform), the area was divided into five blocks, mainly considered non-associated gas projects. During 2002, the first phase of selecting partners was completed. The first exploration phase was completed by PDVSA in July 2003 (see note 8).

The licenses for the exploration and development of blocks two and four were granted by the MEP in February 2003 to ChevronTexaco Corporation, ConocoPhillips and Statoil ASA. These companies are engaged in carrying out a minimum exploratory program with an estimated investment of $150 million and the subsequent investment for its development, if its profitability is confirmed. The participation of PDVSA in the partnership, which could range from between 1% and 35%, will be established when the profitability of each block is determined.

During the second half of 2003, blocks three and five, as redimensioned, were offered. Block three was won by ChevronTexaco Corporation, which was assigned officially by the MEP in February 2004. Block five did not receive offers.

The estimated total investment for this project is approximately $3,810 million, including PDVSA’s participation. Blocks one and five are maintained in reserve for future businesses.

(e) Cooperation Agreement for Orimulsión®

In April 2001, a cooperation agreement for Orimulsión® was signed between BITOR and China National Oil and Gas Exploration and Development Corporation (CNODC), a subsidiary of China National Petroleum Corporation (CNPC), the objective of which is to carry out a series of pre-investments necessary to determine definitively the feasibility of the project. On December 13, 2001, the National Assembly of the Bolivarian Republic of Venezuela authorized BITOR to establish with CNODC, a jointly controlled entity named Orifuels Sinoven, S. A. for production of bitumen, design, construction and operation of an emulsification module of bitumen to produce Orimulsión® (MPE-3); as well as the transportation, exploitation and commercialization of Orimulsión®. BITOR will have a 30% participation, CNODC 40% and PetroChina Fuel Oil Co. Limited 30%. This module shall have an effective production capability of 125 MBPD of Orimulsión® (6.5 MMT), that will be exported to China’s electricity generation market. The production field and facilities will be located in the area of Cerro Negro and Morichal, southern Monagas State, and the emulsification plant in the Industrial Complex in Jose, Anzoátegui State. An initial investment of $330 million is estimated. The Morichal facilities were approximately 30% complete and the Jose plant was approximately 80% complete by June 2005.

(11) Accounts Payable to Suppliers

Accounts payable to suppliers are summarized as follows (in millions of dollars):

F-31

	December 31
	2003	2002
Trade	2,144	2,071
Contractors	486	266
Related entities	121	47
Operating agreements (see note 10(c))	614	466
	3,365	2,850

(12) Taxes

A summary of taxes, which affect the consolidated operations of PDVSA, follows (in millions of dollars):

	Years ended
	December 31
	2003	2002	2001
Income taxes	1,602	149	3,766
Production and other taxes	6,428	5,748	3,760
	8,030	5,897	7,526

(a) Income before Income Taxes

Income before income taxes and minority interests for each year consisted of the following (in millions of dollars):

	Years ended
	December 31
	2003	2002	2001
In Venezuela	3,605	2,283	6,730
Foreign	957	461	1,034
	4,562	2,744	7,764

The income tax expense is summarized as follows (in millions of dollars):

	Years ended
	December 31
	2003		2002		2001
Current income tax expense:
In Venezuela	1,556		663		3,033
Foreign	99		38		130
	1,655		701		3,163
Deferred income tax (benefit) expense:
In Venezuela	(194	)	(613	)	454
Foreign	141		61		149
	(53	)	(552	)	603
Income tax expense	1,602		149		3,766

F-32

The difference between the statutory income tax rate and the effective consolidated income tax rate for each year is analyzed as follows:

	Years ended
	December 31
	2003		2002		2001
	%		%		%

In Venezuela:
Statutory income tax rate for the petroleum sector	50.0		50.0		67.7
Inflation adjustment for tax purposes and effects of translation to dollars	18.0		(79.8	)	(8.4	)
Valuation allowance	(29.2	)	45.8		—
Legal contribution received from subsidiaries	—		—		(6.1	)
FIEM/FEM	(3.2	)	(24.8	)	—
Transfer pricing	(2.8	)	5.2		—
Dividend tax	5.0		0.1		—
Other differences, net	(1.8	)	(3.5	)	(1.4	)
Effective income tax rate in Venezuela	36.0		(7.0	)	51.8
Foreign:
Effects of foreign taxation	(0.9	)	5.4		(3.3	)
Consolidated effective income tax rate	35.1		(1.6	)	48.5

PDVSA and some of its Venezuelan subsidiaries are entitled to tax credits for new investments in property, plant and equipment up to 12% of the amounts invested. Such credits, however, may not exceed 2% of net taxable income, and the carryforward period may not exceed three years. During 2003, some subsidiaries utilized tax credits and tax loss carryforwards of $151 million and $1,984 million, respectively, the tax effect of which amounted to $151 million and $903 million, respectively.

As of December 31, 2003 the investment tax credit carryforwards aggregated approximately $383 million, and tax loss carryforwards were $7 million, which expire as follows (in millions of dollars):

	Years ended
	December 31
	2004	2005	2006
Tax credits	177	105	101
Tax losses	—	5	2

The Venezuelan Income Tax Law introduced an initial adjustment for the effects of inflation for the income tax calculation. The inflation adjusted value of fixed assets is depreciated or depleted over their remaining useful lives for tax purposes. The Tax Law also provides for the calculation of a regular inflation adjustment to be made every year, and included in the reconciliation to taxable income as a taxable or deductible item.

F-33

In conformity with the Venezuelan Income Tax Law, taxpayers subject to income tax who carry out import, export and loan operations with related parties domiciled abroad must determine their income, costs and deductions applying transfer pricing rules. PDVSA has obtained studies supporting its transfer pricing methodology. The resulting effects are included as a taxable or deductible item in the determination of income tax.

In January 2002, the Partial Reform of the Income Tax Law published in November 2001, came into effect. The most important aspects of this Reform are presented below:

• The income tax rate applicable to companies engaged in the production of hydrocarbons and related activities was reduced from 67.7% to 50%. The effect of this change for the year ended December 31, 2001 was an increase in deferred tax expense and a decrease in deferred tax asset as of December 31, 2001 of $97 million.

• The determination of the taxable base for the calculation of income tax results from the sum of territorial income and extraterritorial income. The Reform prohibits offsetting losses from an extraterritorial source against income from a territorial source.

• The methods for determining transfer prices were modified. Furthermore, rules relating to previous transfer pricing agreements were introduced.

The tax effects of significant items comprising PDVSA’s net deferred tax assets (liabilities) are as follows (in millions of dollars):

	December 31
	2003	2002
Deferred tax assets:
Accruals for employee benefits	801	999
Property, plant and equipment	114	391
Production tax payable	—	141
Inventories	58	101
Investment tax credits and tax loss carryforwards	371	1,890
Accruals for contingencies	284	—
Other	49	94
	1,677	3,616
Less valuation allowance	371	1,961
	1,306	1,655
Deferred tax liabilities:
Property, plant and equipment	779	836
Operating agreements, net	—	104
Capitalized interest	—	144
Investments in non-consolidated investees	267	238
Inventories	—	82
Other assets – deferred charges for plant turnaround costs	—	82
Other	48	185
	1,094	1,671
Net deferred tax assets (liabilities)	212	(16	)

F-34

The movement on net deferred tax assets (liabilities) for the year ended December 31, 2002 includes the tax effects of the reversal of the minimum pension liability in Venezuela from other comprehensive income during 2002, amounting to $377 million.

The total deferred tax assets and liabilities were reclassified to present the net current and long-term position indicated as follows (in millions of dollars):

	December 31
	2003		2002
Current assets	257		476
Long-term assets	1,049		454
Current liabilities	(28	)	—
Long-term liabilities	(1,066	)	(946	)
	212		(16	)

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion of deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible and investment tax credits and tax loss carryforwards utilizable. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning in making these assessments. Based upon the level of historical taxable income and projections of future taxable income over periods in which the deferred tax assets are deductible, management believes it is more likely than not that the Company will realize the benefits of these deductible differences, net of the existing valuation allowances at December 31, 2003. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward period are reduced. During 2003, 2002 and 2001, the valuation allowance decreased by $1,590 million, increased by $925 million and increased by $186 million, respectively.

The valuation allowance for deferred tax assets as of January 1, 2003, 2002 and 2001 was $371 million, $1,961 million and $1,036 million, respectively. During 2003, 2002 and 2001, the valuation allowance decreased by $1,590 million, increased by $925 million and increased by $186 million, respectively.

(b) Production Tax

Production tax is payable based on crude oil produced and natural gas processed in Venezuela. Commencing January 2002, the maximum rate of this tax was increased from 16-2/3% to 30% on the volumes of hydrocarbons for the delivery and sale of crude oil to traditional areas (PDVSA Petróleo). For mature reservoirs or extra-heavy crude oil from the Orinoco Belt, a 16-2/3% rate is established to be applied during the first phase of the production, calculated on the basis of certain parameters established by the Venezuelan government. Upon commencement of the commercial production of synthetic crude the rate will be reduced to 1% and maintained at that level during the nine subsequent years or until the income from the sale of the crude triple the value of the initial investment, should that occur before the aforementioned term has elapsed. After the nine-year period, the 16 2/3% rate is reintroduced. These conditions, applicable to the projects of the

F-35

Orinoco Belt were modified (see note 22 (d)). For bitumens, a rate ranging from between 16-2/3% and 30% is used based on the profitability of reservoirs. Royalties for 2003, 2002 and 2001 amounted to $6,298 million, $5,659 million and $3,733 million, respectively, and are included in production and other taxes in the consolidated statement of income.

(c) Business Assets Tax

This tax is as an alternative minimum tax, calculated based on 1% of the average value of the inflation-adjusted assets at the beginning and end of the year. On an individual company basis, PDVSA and its Venezuelan subsidiaries calculate this tax together with income tax and pay the higher of the two. In 2003, 2002 and 2001, this tax resulted in an expense of $24 million, $47 million and $27 million, respectively, included under production and other taxes in the consolidated statement of income (see note 22(d)).

(d) Value Added Tax

The Value Added Tax Law (VAT) effective from June 10, 1999, established a tax rate of 15.5% applicable to the taxable base, and in August 2000, the rate was modified to 14.5%. Effective from September 2002, the applicable rate was 16% (see note 22(d)). The VAT Law provides for an exemption for the commercialization of certain hydrocarbon derivative products and the right to recover from the National Treasury certain tax credits resulting from export sales. Amounts to be recovered do not bear interest. A consolidated summary of tax credits pending compensation or recovery follows (in millions of dollars):

	Years ended
	December 31
	2003		2002		2001
Tax credits receivable at beginning of year	1,933		2,150		1,475
Generated during the year	453		753		1,022
Exchange loss	(236	)	(970	)	(138	)
Recovered during the year	—		—		(209	)
Tax credits receivable at end of year	2,150		1,933		2,150

(e) Sales and Excise Taxes

In Venezuela and the United States of America, sales of gasoline and other motor fuels are subject to sales and excise taxes. In 2003, 2002 and 2001, such taxes, paid to the corresponding governments, amounted to $3,766 million, $3,623 million and $4,133 million, respectively. These taxes are presented as a reduction from sales in the consolidated statement of income.

(f) Surface Tax

The Organic Hydrocarbons Law establishes the payment of a tax equivalent to 100 tax units (TU) per square kilometer or fraction of surface extention of land granted and not exploited. This tax will be increased annually by 2% during the first five years and by 5% in subsequent years. During 2003 and 2002, PDVSA Petróleo incurred surface tax in Venezuela of $106 million and

F-36

$42 million, respectively, included under production and other taxes in the consolidated statement of income.

(13) Financial and Derivative Instruments

(a) Commodity Derivative Activity and Interest Rate Swap and Cap Agreements

PDVSA uses commodity and financial instrument derivatives to manage defined commodity price and interest rate risks arising out of the Company’s core business activities, and does not use them for trading or speculative purposes. The Company’s commodity derivatives are generally entered into through major brokerage houses and are traded on national exchanges and can be settled in cash or through delivery of the commodity.

PDVSA enters into petroleum futures contracts, options and other over-the-counter commodity derivatives principally to manage a portion of the risk associated with market price movements of crude oil and refined products. The Company’s derivative commodity activity is undertaken within limits established by management and contract duration is generally less than 30 days.

Furthermore, PDVSA enters into various interest rate swap agreements to manage the risk related to interest rate fluctuations on its debt.

(b) Concentration of Credit Risk

The Company’s financial instruments that are exposed to concentrations of credit risk consist principally of its cash equivalents, derivative financial instruments and notes and accounts receivable. The Company’s cash equivalents are in high-quality securities placed with a wide array of institutions. Similar standards of creditworthiness and diversity are applied to the Company’s counterparties to derivative instruments. Notes and accounts receivable balances are dispersed among a broad customer base worldwide and the Company routinely assesses the financial strength of its customers. The Company’s credit risk is dependent on numerous additional factors including the price of crude oil and refined products, as well as the demand for and the production of crude oil and refined products.

(c) Fair Value of Financial Instruments

The following estimated fair value amounts have been determined by the Company using available market information and appropriate valuation methodologies. However, considerable judgment is required for interpreting market data to develop the estimates of fair value. Accordingly, the estimates presented herein are not necessarily indicative of the amounts that the Company could realize in a current market exchange. The use of different market assumptions and/or estimation methodologies could have a material effect on the estimated fair value amounts (in millions of dollars):

F-37

	December 31
	2003		2002
	Carrying amount	Fair value	Carrying amount	Fair value
Assets:
Cash and cash equivalents	2,938	2,938	1,703	1,703
Restricted cash	961	961	1,772	1,772
Notes and accounts receivable	4,955	4,955	3,515	3,515
Recoverable value added tax	2,150	1,919	1,933	1,693
Long-term accounts receivable (included in other assets)	680	680	669	583
Derivative assets (included in prepaid expenses and other assets)	20	20	3	3

Liabilities:
Account payable to suppliers	3,365	3,365	2,850	2,850
Current portion of long-term debt	750	737	1,817	1,770
Long-term debt, net of current portion	6,265	6,186	6,426	5,851
Derivative liabilities (included in accrued and other liabilities)	8	8	36	36

The carrying amounts of cash and cash equivalents, notes and accounts receivable and accounts payable to suppliers approximate their fair value due to the short maturity of these instruments.

Restricted cash bears interest at variable market rates, and the carrying amount approximates fair value.

The fair value of recoverable value added tax has been determined by discounting the non-interest bearing carrying value, based on future estimated recoveries, using interest rates applicable in the money market.

Long-term accounts receivable result mainly from transactions with related parties and their carrying value as of December 31, 2003 approximates fair value.

The fair value of long-term debt, including the current portion, at December 31, 2003 and 2002, is based on interest rates that are currently available to PDVSA for issuance of debt with similar terms and remaining maturities and broker quotes which contemplate credit risk.

The fair value of derivative instruments is based on the estimated amount that the Company would receive or pay to terminate the agreements, considering current commodity prices and interest rates and the current creditworthiness of the counterparties.

(14) Long-Term Debt and Credit Facilities

Long-term debt consists of the following (in millions of dollars):

F-38

	December 31
	2003	2002
PDV America/CITGO:
7.25% to 7.87% unsecured senior notes, due 2003	—	499
2.4% to 2.5% unsecured revolving bank loans, due 2003-2005	—	279
Variable rate senior secured term loan with CITGO’s stock participation in two affiliates, due 2006	200	—
7.875% unsecured senior notes under $600 shelf registration, due 2006	150	200
9.3% unsecured private placement senior notes, due 2003 to 2006	34	46
7.17% to 8.94% unsecured master shelf agreement senior notes, due 2003-2009	185	235
Variable and fixed rate 2.1% to 8.3% guaranteed tax-exempt bonds, due 2004 to 2033	332	426
Variable rate taxable bonds guaranteed with letters of credit, due 2026 to 2028	25	115
11.375% unsecured senior notes, due 2011	547	—
	1,473	1,800
PDVSA Finance – Unsecured notes: (see note 22 (c)):
6.45% due 2002 through 2004	50	250
8.75% due 2000 through 2004	28	127
6.25% due 2002 through 2006 (in euros)	142	171
6.65% due 2004 through 2006	300	300
9.37% due 2004 through 2007	250	250
6.80% due 2007 through 2008	300	300
9.75% due 2008 through 2010	250	250
8.50% due 2010 through 2012	500	500
7.40% due 2014 through 2016	400	400
9.95% due 2018 through 2020	100	100
7.50% due 2027 through 2028	400	400
Treasury notes	—	(4	)
	2,720	3,044
PDVSA VI:
8.46% notes guaranteed by PDVSA and the stock participation in Hovensa, due 2003 to 2009	334	395

PDVSA Petróleo:
Variable and fixed rate (2.44% to 6.55%) loans guaranteed by governmental export agencies and financial institutions, due 2004 to 2005	92	185
7.33% to 8.03% PDVSA Cerro Negro bonds guaranteed with property, plant and equipment, due 2003 to 2028	276	288
Variable rate (LIBOR plus 1% to 1.5%) PDVSA Cerro Negro line of credit guaranteed with property, plant and equipment, due 2003 to 2012	121	136
Variable rate (LIBOR plus 0.875% to 2.125%) PDVSA Sincor loan guaranteed with property, plant and equipment and by the partners of the project, due 2003 to 2012	432	456
Variable rate (LIBOR plus 0.875% to 3.5%) Corpoguanipa lines of credit guaranteed with property, plant and equipment and by the partners of the project, due 2008 to 2018	291	284
	1,212	1,349
Bariven, S.A. (Bariven):
Variable and fixed rate (1.09% to 6.13%) loans guaranteed by governmental export agencies and financial institutions, due 2003 to 2008	234	348

PDV Marina, S.A. (PDV Marina):
Variable rate (2.8125% to 3.65625%) letters of credit facility guaranteed with tankers, transfer of rights on freight contracts and management, due 2003 to 2006	87	136

PDVSA Corporate:
Variable rate (LIBOR plus 0.5%) loan agreement guaranteed by governmental export agencies and financial institutions, due 2008	600	475
Variable rate (1.7% to 2.3%) loan agreement guaranteed by governmental export agencies and financial institutions, due 2012 (in yen)	280	250
Unsecured variable rate (LIBOR plus 0.45%) loan facility, due 2010	18	370
	898	1,095
Other subsidiaries, including $16 payable in bolivars at December 31, 2003 ($11 at December 31, 2002)	57	76
	7,015	8,243
Less current portion of long-term debt	750	1,817
Total long-term portion	6,265	6,426

F-39

Future maturities of the long-term portion at December 31, 2003 are as follows (in millions of dollars):

Years
2005		751
2006		848
2007		638
2008		732
Remaining years		3,296
		6,265

All debt is denominated in dollars except for the Euro and Yen denominated loans as indicated above.

Covenants

Various of PDVSA’s borrowing facilities contain covenants that restrict, among other things, the ability of the Company and its subsidiaries to incur additional debts, to pay dividends, place liens on property and sell certain assets. The Company was in compliance with these covenants at December 31, 2003 and 2002.

Credit Facilities

PDVSA and its subsidiaries have the following unused credit facilities available at December 31, 2003 (in millions of dollars):

F-40

Loan agreements-secured		163
Lines of credit-secured		39
Lines of credit-unsecured		260
		462

(15) Capital Stock and Reserves

At December 31, 2003 and 2002, PDVSA’s capital stock is represented by 51,204 registered shares of Bs25 million each, totaling $39,094 million. By law the shares may not be transferred or encumbered in any way.

The legal reserve is a requirement for Venezuelan companies. Pursuant to Venezuelan law, the legal reserve shall not be distributed as dividends. Other reserves include principally the reserve for the realization of deferred tax asset and the reserve for new investments.

Cash dividends paid to the shareholder are declared and paid in bolivars based on the statutory financial statements, which reflect retained earnings. Non-cash dividends with a fair value of $251 million and $63 million were paid to the shareholder in 2003 and 2001, respectively. In 2003, 2002 and 2001, total cash and non-cash dividends were declared equivalent to Bs4,150,000 million, Bs3,400,000 million and Bs3,400,000 equivalent, in US dollars, to $2,594 million, $2,752 million and $4,774 million, respectively.

(16) Employee Benefit Plans

An analysis of the liability for employee benefit plans follows (in millions of dollars):

	December 31
	2003	2002

Accrual for employee termination benefits	131	111
Pension plans	795	1,672
Other postretirement benefits	1,245	1,043
	2,171	2,826
Less current portion	263	431
Long-term portion	1,908	2,395

PDVSA and its subsidiaries have the following employee benefit plans:

(a) Defined Contribution Savings Plans

PDVSA and its Venezuelan subsidiaries maintain savings funds for their employees and guarantee contributions to the members’ accounts. At December 31, 2003 and 2002, the guaranteed amount in the savings fund is $165 million and $160 million, respectively. In addition, a U.S. subsidiary maintains three retirement and savings plans with defined contributions, covering all eligible employees; the employees who are members of these plans make voluntary contributions to the plans that in turn are matched by the subsidiary.

F-41

(b) Pension Plans and Other Postretirement Benefits

Pursuant to the collective labor contract, PDVSA and its Venezuelan subsidiaries have a retirement plan that covers all eligible employees. There is a single pension fund and an organization which administers the assets of the pension plan. The pension plan is terminally funded for most of the retirees’ liabilities. A U.S. subsidiary also sponsors three qualified noncontributory defined benefit pension plans and three nonqualified defined benefit plans. The qualified pension plans are funded in accordance with current legislation, without exceeding tax deduction restrictions. The nonqualified plans are funded as necessary to pay retiree benefits.

In addition to pension plans, PDVSA provides social benefits and medical and life insurance for retired personnel. These benefits are funded on a pay-as-you-go basis.

PDVSA and some of its Venezuelan subsidiaries have a foreign currency denominated pension obligation measured under the U.S. dollar method and remeasured into the reporting currency (dollar) before calculating actuarial gains and losses. Foreign currency gains and losses from remeasurement of the bolivar pension obligation are treated as actuarial gains and losses and therefore are subject to deferral and amortization of the corridor.

The following sets forth the changes in benefit obligations, plan assets for the pension plans, and the funded status of such plans and postretirement benefits for 2003 and 2002, and the funded status of such plans reconciled with amounts reported in the consolidated balance sheets (in millions of dollars):

	Years ended December 31
	2003		2002		2003		2002
	Pension benefits				Other postretirement benefits
Venezuela:
Change in benefit obligation
Benefit obligation, beginning of year	2,734		4,240		1,096		1,462
Service cost	51		152		26		52
Interest cost	204		414		94		143
Participant contributions	8		12		—		—
Plan amendments	452		180		—		6
Actuarial gains	(118	)	(2,091	)	(32	)	(494	)
Benefits paid	(184	)	(173	)	(52	)	(73	)
Curtailments	(835	)	—		(212	)	—
Benefit obligation, end of year	2,312		2,734		920		1,096

F-42

	Years ended December 31
	2003		2002		2003		2002
	Pension benefits				Other postretirement benefits
Change in plan assets
Fair value of plan assets, beginning of year	1,054		1,199		—		—
Actual return on plan assets	575		(592	)	—		—
Employer contributions	120		501		—		73
Participant contributions	8		12		—		—
Benefits paid	(137	)	(66	)	—		(73	)
Fair value of plan assets, end of year	1,620		1,054		—		—

Funded status	(692	)	(1,680	)	(920	)	(1,096	)
Employer contributions	9		11		—		—
Benefit payments made directly by employer	32		5		—		—
Unrecognized net actuarial gain	(1,042	)	(475	)	(196	)	(147	)
Unrecognized prior service cost	1,053		1,256		200		457
Unrecognized transition obligation	—		2		—		—
Net amount recognized	(640	)	(881	)	(916	)	(786	)

F-43

	Years ended December 31
	2003		2002		2003		2002
	Pension benefits				Other postretirement benefits
Amounts recognized in the Company’s
consolidated balance sheets consist of:
Accrued benefit liability	(681	)	(1,574	)	(916	)	(786	)
Employer contributions	9		10		—		—
Benefit payments made directly by employer	32		5		—		—
Intangible asset	—		678		—		—
Net amount recognized	(640	)	(881	)	(916	)	(786	)
Foreign:
Change in benefit obligation
Benefit obligation, beginning of year	450		391		334		261
Service cost	20		17		9		7
Interest cost	29		28		22		19
Amendments	(8	)	—		(4	)	—
Actuarial loss	39		29		62		55
Plan merger/acquisitions	5		—		—		—
Accumulated other comprehensive Income	(19	)	(15	)	(8	)	(8	)
Benefit obligation, end of year	516		450		415		334
Change in plan assets -
Fair value of plan assets, beginning of year	290		324		1		1
Actual return on plan assets	59		(28	)	—		—
Plan merger/acquisitions	4		—		—		—
Employer contributions	24		9		8		8
Benefits paid	(34	)	(15	)	(8	)	(8	)
Fair value of plan assets, end of year	343		290		1		1
Funded status	(173	)	(159	)	(413	)	(333	)
Unrecognized net actuarial loss	90		91		87		75
Unrecognized prior service cost	(6	)	2		(4	)	—
Net amount recognized	(89	)	(66	)	(330	)	(258	)

F-44

	December 31
	2003		2002		2003		2002
	Pension benefits				Other postretirement benefits
Amounts recognized in the Company’s consolidated balance sheets consist of-
Accrued benefit liability	(114	)	(97	)	(330	)	(258	)
Intangible asset	—		2		—		—
Accumulated other comprehensive income	25		29		—		—
Net amount recognized	(89	)	(66	)	(330	)	(258	)

F-45

The net periodic benefit (reversal) costs are as follows (in millions of dollars):

	Years ended December 31
	2003		2002		2001		2003		2002	2001
							Other postretirement
	Pension benefits						benefits
Venezuela:
Components of net periodic benefit (reversal) cost
Service cost	51		152		142		26		52	52
Interest cost	204		414		386		94		143	135
Expected return on plan assets	(104	)	(120	)	(121	)	—		—	—
Amortization of prior service cost	87		118		118		44		68	68
Amortization of net gain at date of adoption	2		2		2		—		—	—
Recognized net actuarial (gain) loss	(22	)	44		45		(7	)	18	26
Curtailments/settlements	(267	)	—		—		25		—	—
Net periodic benefit (reversal) cost	(49	)	610		572		182		281	281

Foreign:
Components of net periodic benefit cost
Service cost	20		17		16		9		7	6
Interest cost	29		28		26		22		19	16
Expected return on plan assets	(27	)	(30	)	(31	)	—		—	—
Amortization of prior service cost	—		—		—		—		—	—
Recognized net actuarial (gain) loss	3		—		(3	)	50		11	—
Net periodic benefit cost	25		15		8		81		37	22

Additional information for Venezuela is presented below:

	2003	2002	2001	2003	2002	2001
	Pension			Other postretirement
	Benefits			Benefits
	%	%	%	%	%	%
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	10.00	10.00	10.00	10.00	10.00	10.00
Rate of compensation increase	7.00	7.00	7.00	7.00	7.00	7.00
Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31:
Discount rate	10.00	10.00	10.00	10.00	10.00	10.00
Rate of compensation increase	7.00	7.00	7.00	7.00	7.00	7.00
Expected return on plan assets	10.00	10.00	10.00	—	—	—

F-46

In Venezuela the rate of return of the plan’s assets generally reflects the historic return of the assets, according to the structure of the investment portfolio. At December 31, 2003, the weighted average return of the investment portfolio over the last ten years was 29.9%.

In Venezuela, for the purpose of benefits other than pension plans, an 8% incremental inflation rate is applied for health benefits and 6% for food subsidy plans.

The inflation rate increments on these benefits have a significant effect on the reported quantities for these plans. A one percent variation in the rates would have the following effects (in millions of dollars):

	1% increase	1% decrease
Increase (decrease) in total service and interest cost components	20	(16	)
Increase (decrease) in postretirement benefit obligation	123	(102	)

The measurement date to determine the amounts of assets and liabilities of the pension plan was December 31, 2003.

F-47

Additional information for foreign subsidiaries is presented below:

	2003	2002	2001	2003	2002	2001
	Pension			Other postretirement
	benefits			benefits
	%	%	%	%	%	%
Weighted-average assumptions used to determine benefit obligations at December 31:
Discount rate	6.25	6.75	7.25	6.25	6.75	7.25
Rate of compensation increase	4.46	5.00	5.00	—	—	—

	2003	2002	2001	2003	2002	2001
	Pension			Other postretirement
	benefits			benefits
	%	%	%	%	%	%
Weighted-average assumptions used to determine net periodic benefit cost for the year ended December 31:
Discount rate	6.75	7.25	7.25	6.75	7.25	7.25
Expected long-term return on plan assets	8.50	9.00	9.00	8.50	9.00	6.00
Rate of compensation increase	5.00	5.00	5.00	—	—	—

CITGO’s expected long-term rate of return on plan assets is intended to generally reflect the historical returns of the assets in its investment portfolio. The weighted average return at December 31, 2003 on indices representing CITGO’s investment portfolio is 7.94% over the past 10 years and 8.84% over the past 15 years.

For measurement purposes, a 10 percent pre-65 and an 11 percent post-65 annual rate of increase in the per capita cost of covered health care benefits was assumed for 2003. These rates are assumed to decrease 1 percent per year to an ultimate level of 5 percent by 2009 for pre-65 and 2010 for post-65 participants, and to remain at that level thereafter.

Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects (in millions of dollars):

F-48

	1% increase	1% decrease
Increase (decrease) in total service and interest cost components	6	(5	)
Increase (decrease) in postretirement benefit obligation	69	(55	)

In the United States, in December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 (“Medicare Reform”) was signed into law. Medicare Reform introduces a prescription drug benefit under Medicare (Medicare Part D) as well as a non-taxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. In May 2004, the FASB Staff issued FASB Staff Position No. FAS 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003”. The Staff Position permits a sponsor to report the effects of Medicare Reform prospectively in the third quarter of 2004 or retrospectively to the measurement date following enactment of the legislation. CITGO has chosen to use the retrospective method to reflect Medicare Reform as of January 1, 2004. The effect of this legislation at that date was to reduce the benefit obligation by approximately $40 million. The service cost and interest cost components of that reduction total approximately $3 million. Under CITGO’s accounting policy for recognizing actuarial gains, net periodic benefit cost for the year ended December 31, 2004 was reduced $40 million related to this actuarial gain.

Plan Assets

For Venezuela the plan assets include:

	Target	December 31
Asset category	allocation	2003	2002
	%	%	%
Equity	22	23.30	4.13
Fixed income	30	29.36	22.69
Cash	48	47.34	73.18
	100	100	100

The investment return objective for these assets is to achieve returns that meet or exceed the actuarial discount rate over time. This is to be accomplished using a well-diversified portfolio structure. The Company periodically reviews the asset allocation to determine whether it remains appropriate for achieving the investment return objective.

Contributions

In accordance with Venezuelan policy for contributions to pension plan funds, the Company contributes to the selected plan, 9% of the integral salary to each individual employee account. At the time the employee retires, the Company then contributes the difference between the current value of the pensions and the outstanding accrued amount to the selected plan. For 2004, PDVSA estimates contributions of $81 million.

With regard to the policy to constitute funds for benefits other than retirement plan, the “pay-as-you-go” method is applied, PDVSA estimates contributions for these plans in 2004 will be $51 million.

F-49

For foreign subsidiaries the plan assets include:

	Target	December 31
Asset category	allocation	2003	2002
	%	%	%
Equity	60	60.20	52.16
Fixed income	40	39.20	46.73
Cash	0	0.60	1.11
	100	100	100

Contributions

For foreign plans, the policy is to fund the qualified pension plans in accordance with applicable laws and regulations and not to exceed the tax-deductible limits. CITGO estimates that it will contribute $58 million to these plans in 2004. The nonqualified plans are funded as necessary to pay retiree benefits. The plan benefits for each of the qualified pension plans are primarily based on an employee’s years of plan service and compensation as defined by each plan.

CITGO’s policy is to fund its postretirement benefits other than its pension obligations, on a pay-as-you-go basis. CITGO estimates that it will contribute $10 million to these plans in 2004.

(17) Accrued and Other Liabilities

Accrued and other liabilities are summarized as follows (in millions of dollars):

	December 31
	2003	2002
Withholding taxes	258	109
Valued added tax (VAT)	201	230
Production tax payable	637	288
Capital leases (see note 8)	46	98
Long-term accounts payable	88	334
Provision for lawsuits and claims (see note 20)	380	46
Employees’ accounts payable	134	421
Environmental accrual (see note 20)	473	58
Accrual for refining works	50	—
Accrual for asset retirement obligations (see note 8)	537	—
Interest payable	111	117
Dividends payable	126	109
Accrued expenses	396	204
Other	138	331
	3,575	2,345
Less current portion of accrued and other liabilities	2,293	1,757
Long-term portion	1,282	588

F-50

(18) Related Party Transactions

PDVSA considers its affiliates, companies controlled jointly, the Company’s directors and executives, other companies that are also property of the stockholder and other government institutions as related parties.

A summary of transactions with related parties follows (expressed in millions of dollars):

	Years ended December 31
	2003	2002	2001

Activities of the year:
Sales	6,022	6,602	4,167
Equity in earnings of non-consolidated investees	379	268	464
Costs and expenses	5,690	6,402	4,991

	December 31
	2003	2002
Balances at year-end:
Deposits with the BCV, contributions to the FEM (see notes 2 and 4)	698	2,382
Trust signed with the Banco de Desarrollo Económico y
Social de Venezuela (BANDES), for social programs and projects (see note 4)	302	—
Accounts receivable (see note 5)	436	328
Long-term accounts receivable included in other assets (see note 9)	680	669
Investments in affiliates (see note 7)	3,072	2,854
Accounts payable to suppliers, accrued and other liabilities	758	684

Long-term accounts receivable as of December 31, 2003 and 2002, include balances with Petrozuata for $234 million and $490 million, respectively, which are held for cash requirements; also, they include balances receivable from C. A. de Administración y Fomento Eléctrico (CADAFE) for $220 million and $132 million, respectively. The accounts receivable from CADAFE result from services provided, industrial distribution, and methane gas transportation. Also, the supply of light diesel, by the subsidiaries of PDVSA Gas, Deltaven and PDVSA Petróleo, may be offset against energy supply services provided by CADAFE. During 2003 and 2002, PDVSA, through its subsidiary PDVSA Petróleo, offset with CADAFE $16 million and $17 million, respectively.

In 2003, PDVSA and CADAFE entered into a cooperation agreement whereby PDVSA, through PDVSA Petróleo, acquired certain assets for $70 million that are included in property, plant and equipment as construction in progress at December 31, 2003. These assets will be transferred to CADAFE and the costs involved, derived from or associated with this operation, will be recovered by PDVSA through discounts and/or supply of electric power by CADAFE.

During 2003, 2002 and 2001, PDVSA purchased upgraded crude oil from Petrozuata amounting to $196 million, $261 million and $301 million, respectively, which is included in costs and expenses. Additionally, Petrozuata reimbursed PDVSA for project and operating expenditures amounting to $14 million, $11 million and $68 million in 2003, 2002 and 2001, respectively (see notes 7 and 10).

F-51

In 2002, the affiliated company, INTESA invoiced PDVSA for information technology services of $253 million, which are included in costs and expenses (see note 20).

PDVSA Petróleo has various agreements for supplies with affiliated companies, which are summarized as follows (MBPD):

Affiliate	Delivery obligation	Year of termination
Ruhr Oel	237	2022
AB Nynäs petroleum	57	2005
LYONDELL-CITGO (see note 20)	230	2017
Chalmette Refining	90	Strategic association period
ConocoPhillips	172	2020
Hovensa	270	Between 2008 and 2022
	1,056

During the years ended December 31, 2003, 2002 and 2001, CITGO acquired refined products from various affiliated companies, LYONDELL-CITGO, Hovensa and Chalmette Refining under long-term agreements. These purchases amounted to $4,900 million, $3,500 million and $3,400 million, respectively, and are included in the consolidated statement of income as purchases of crude oil and products. At December 31, 2003 and 2002, accounts payable resulting from these operations amounted to $148 million and $110 million, respectively.

During 2003, 2002 and 2001, CITGO sold to affiliated companies refined products and other refinery supplies of $387 million, $277 million and $248 million, respectively. The outstanding balances resulting from these operations at December 31, 2003 and 2002 amounted to $71 million and $94 million, respectively, that are included in notes and accounts receivable from related parties (see note 5).

During 2003, PDVSA through CVP, and as part of the process to support the social projects carried out by the National Government, donated to the Bolivarian Republic of Venezuela $251 million in non-cash materials purchased from the counterparty to the energy cooperation and integration agreement described below. This donation was expensed during 2003 and is included in costs and expenses. The debt created by CVP’s purchases from this counterparty was later paid through an offset of trade accounts receivable due from an affiliate of the counterparty. The trade accounts receivable that were offset were derived from sales made in connection with the Caracas energy cooperation and integration agreement “Convenio de Cooperación y de Integración Energética de Caracas” that was transferred from PDVSA Petróleo to CVP (see note 22(a)).

As part of the support for various programs established by the National Government during 2003, PDVSA has made contributions for donations and to social Missions for $22 million and $227 million, respectively, that are included as costs and expenses in the statement of income (see note 22(a)).

(19) Operating Segments and Geographic Data

Intersegment sales, which primarily consist of sales of crude oil, are generally made at approximate market prices. PDVSA evaluates the performance of its segments and allocates resources to them based on net revenues, operating income (calculated as income before financing expenses and income taxes), capital

F-52

expenditures and property, plant and equipment. The “other” line item includes corporate related items and results of non-significant operations in Venezuela, Europe and the Caribbean.

The exploration, production and upgrading segment in Venezuela, include the search for oil and gas reserves, and improvement of extra-heavy crudes; and the transportation of crude and natural gas to the point of delivery to the refineries and fractionation plants.

Refining, supply and marketing activities in Venezuela include the administration of refineries, marketing and transportation of crude oil, natural gas and refined petroleum products under the brand name PDV. Petrochemical activities in Venezuela cover the production and marketing of various compound mixes, olefins, plastic resins and chemical additives. Refining, supply and marketing activities in the United States of America cover the administration of refineries and the marketing of gasoline and refined petroleum products in the eastern and midwestern regions under the brand name CITGO.

F-53

Summarized financial information for the Company’s reportable segments is presented in the following table (in millions of dollars):

	Years ended December 31
	2003		2002		2001
Revenues:
Net sales of crude oil and products:
Segments in Venezuela:
Upstream operations	21,241		18,931		20,480
Downstream operations	22,026		23,342		25,903
Petrochemical operations	784		919		1,070
Segments in the United States of America:
Downstream operations	25,217		19,358		19,601
Other	714		645		851
	69,982		63,195		67,905
Eliminations (1)	(23,393	)	(20,615	)	(21,655	)
	46,589		42,580		46,250
Operating income (2):
Segments in Venezuela:
Upstream operations	8,320		4,032		7,653
Downstream operations	(4,117	)	(583	)	(1,348	)
Petrochemical operations	42		265		(104	)
Segments in the United States of America:
Downstream operations	762		314		658
Other	670		464		2,534
	5,677		4,492		9,393
Eliminations (1)	(488	)	(985	)	(1,120	)
	5,189		3,507		8,273
Depreciation:
Segments in Venezuela:
Upstream operations	1,571		1,718		1,714
Downstream operations	821		819		441
Petrochemical operations	126		145		114
Segments in the United States of America:
Downstream operations	263		300		286
Other	43		56		69
	2,824		3,038		2,624

(1) Represents the elimination of intersegment sales.

(2) Before financing expenses, income taxes, minority interests and cumulative effect of accounting change for asset retirement obligations.

F-54

	Years ended December 31
	2003	2002		2001
Capital expenditure, net:
Segments in Venezuela:
Upstream operations	1,276	1,316		764
Downstream operations	237	814		2,517
Petrochemical operations	9	(172	)	110
Segments in the United States of America:
Downstream operations	357	754		292
Other	90	31		98
	1,969	2,743		3,781
Property, plant and equipment, net:
Segments in Venezuela:
Upstream operations	19,951	20,415		21,673
Downstream operations	8,324	9,024		8,899
Petrochemical operations	1,808	1,925		2,241
Segments in the United States of America:
Downstream operations	3,833	3,750		3,293
Other	804	757		782
	34,720	35,871		36,888

Net sales and long-lived assets information by geographic area are summarized below (in millions of dollars):

	Venezuela	United States of America	Other Countries (3)	Total
December 31, 2003
Net sales (1)	20,659	25,216	335	46,210
Long-lived assets (2)	37,834	5,039	2,178	45,051

December 31, 2002
Net sales (1)	22,309	19,358	645	42,312
Long-lived assets (2)	37,874	5,086	1,320	44,280

December 31, 2001
Net sales (1)	26,184	19,602	—	45,786
Long-lived assets (2)	40,402	4,432	2,351	47,185

(1) Based on the country in which the sales originate.

(2) Based on the location of the asset.

(3) The long-lived assets consist primarily of investments in non-consolidated investees.

F-55

(20) Commitments and Contingencies

Guarantees and Other Commitments

As of December 31, 2003, some of PDVSA’s subsidiaries have construction completion guarantees related to debt and financing arrangements secured by joint venture projects. The subsidiaries, projects, guarantee obligations and year of termination are presented below (in millions of dollars):

Subsidiary/Project	Guarantee obligations	Year of termination
PDV Holding Inc./Merey Sweeny, L.P. (MSLP)	175	2004
CITGO/affiliates and other	53	2004-2009
PDVSA Petróleo/Hamaca Project	291	2005
PDVSA Petróleo/Sincor Project	16	2005
PDVSA Petróleo/Ministry of Environment	34	2007

PDVSA and its affiliates have guaranteed the debt of others in a variety of circumstances including letters of credit, bank debt and customer debt amounting to $100 million as of December 31, 2003. No liabilities have been recorded for these amounts.

Litigation and Other Claims

In August 1999, the U.S. Department of Commerce rejected a petition filed by a group of independent oil producers to apply antidumping measures and countervailing duties against imports of crude oil from Venezuela and some other countries. The petitioners appealed this decision before the U.S. Court of International Trade based in New York. On September 19, 2000, the Court of International Trade remanded the case to the Department of Commerce with instructions to reconsider its August 1999 decision. The Department of Commerce was required to make a revised decision as to whether or not to initiate an investigation. The Department of Commerce appealed to the U.S. Court of Appeals for the Federal Circuit, which dismissed the appeal as premature on July 31, 2001. The Department of Commerce issued its revised decision, which again rejected the petition, in August 2001. The revised decision was affirmed by the Court of International Trade on December 17, 2002. In February 2003, the independent oil producers appealed the Court of International Trade’s decision to the Federal Circuit. On January 30, 2004 the U.S. Court of Appeals for the Federal Circuit affirmed the decision of the Court of International Trade.

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calculate interest. LYONDELL-CITGO also claims additional unspecified amounts for attorneys’ fees and costs. Discovery was formally concluded on October 1, 2004. On October 1 and October 6, 2004, the magistrate judge issued orders directing PDVSA and PDVSA Petróleo to produce all Board of Directors minutes and related documents to LYONDELL-CITGO. PDVSA informed the magistrate judge that it could not comply with his order because granting LYONDELL-CITGO unrestricted access to PDVSA’s Board of Directors materials violated Venezuelan law. The magistrate judge entered an adverse inference sanction against PDVSA and PDVSA Petróleo, ordering that the court may infer that the Board of Directors’ documents were unfavorable to PDVSA and favorable to LYONDELL-CITGO. The magistrate judge also ordered that the court may give the strongest weight to the evidence already in the case in favor of LYONDELL-CITGO, but may also consider any evidence presented by PDVSA to explain why it did not produce the Board of Directors materials. The judge affirmed the magistrate judge’s adverse inference instruction on April 29, 2005. Meanwhile, on October 22, 2004, both parties filed motions for summary judgment with the court, which have been fully briefed. These motions are still pending. Management of the companies intends to contest vigorously LYONDELL-CITGO’s claims.

On April 11, 2003, a legal action was filed against PDVSA and its subsidiaries PDVSA Petróleo, PDVSA Finance and CITGO in the federal district court of Denver, Colorado, USA. The plaintiff is a U.S. oil and gas exploration and production company that has allegedly entered into an exclusive offshore license agreement with the government of Grenada to explore, develop, produce and market oil and/or natural gas in 4.75 million offshore acres between Grenada and Venezuela. The plaintiff alleges that PDVSA has interrupted and otherwise interfered with its ability to develop and market Grenada’s oil and natural gas resources in violation of the U.S. antitrust laws. The plaintiff seeks damages in an amount to be established at trial that it believes should exceed $100 million. The companies deny the allegations and complaints and intend to contest the case vigorously if it proceeds. In November 2003, the plaintiff filed a Notice of Dismissal, without prejudice, with respect to PDVSA Finance. The defenses will continue for the case of PDVSA, PDVSA Petróleo and CITGO. On September 30, 2004 the court, where the case is dealt with, announced a decision favorable to PDVSA. The plaintiff appealed against the final outcome of the case, and the decision relating to that appeal is pending. Management and their legal counsel believe that the companies have substantial defenses.

The work stoppage promoted by some sectors during December 2002 and the first months of 2003 which interrupted the operations of PDVSA and its Venezuelan subsidiaries (see note 21), resulted in the termination of the labor relationship, beginning January 1, 2003, for approximately 18,000 workers of PDVSA and its subsidiaries in Venezuela (of its then total labor force of approximately 45,000 workers). In the opinion of PDVSA’s management and its legal advisors, the dismissals were carried out in conformity with the Venezuelan Organic Labor Law (LOT), and all the significant outstanding labor benefits, pursuant to PDVSA’s collective labor contract and the Venezuelan LOT, have been accrued for as of December 31, 2003 and 2002. The employees fired from PDVSA have filed a re-hiring request with the labor court. Management and their legal counsel believe that this matter will be resolved in favor of the Company.

PDVSA previously outsourced its information technology services to INTESA, based on a joint venture and a services agreement. INTESA is a Venezuelan company owned 60% by SAIC Bermuda Ltd. and 40% by PDV-IFT, a subsidiary of PDVSA. PDVSA gave notice of termination of the services agreement, in accordance with the contract, on June 28, 2002. PDVSA has proposed a plan to jointly liquidate INTESA and to honor all valid obligations with the employees and providers. PDVSA has been assigned and has paid a significant portion of INTESA’s obligations with providers, which will be offset against the debt that

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PDVSA has with INTESA. Management and their legal counsel believe that this matter will be resolved in favor of the Company.

In May 2003, an arbitration proceeding was commenced in the International Court of Arbitration against PDVSA Petróleo in connection with a dispute arising under an alleged contract for the sale and purchase of 50,000 MMT of unleaded gasoline dated February 19, 2003. The plaintiffs are claiming for damages amounting to $14 million. Management and their legal advisors deny the allegations and have contested the claims vigorously. Management and their legal counsel believe that they have substantial defenses to the claims asserted.

The Company is involved in various other claims and legal actions in the ordinary course of business amounting to $2,900 million. In the opinion of management, the ultimate disposition of these matters will not have a material adverse effect on the Company’s consolidated financial position, results of operations, or liquidity.

Based on an analysis of the available information, a provision as of December 31, 2003 and 2002, amounting to $380 million and $46 million, respectively, is included in accrued and other liabilities relating to all the contingencies described above (see note 17). If known lawsuits and claims were to be determined in a manner adverse to the Company, and in amounts greater than the Company’s accruals, then such determinations could have a material adverse effect on the Company’s results of operations in a given reporting period. Although it is not possible to predict the outcome of these matters, management, based in part on advice of its legal counsel, does not believe that it is probable that losses associated with the proceedings discussed above, that exceed amounts already recognized, will be incurred in amounts that would be material to the Company’s financial position or results of operations.

Environmental Compliance and Remediation

The majority of PDVSA’s subsidiaries, both in Venezuela and abroad, are subject to various environmental laws and regulations under which they may be required to make significant expenditures to modify their facilities and to prevent or remedy the environmental effects of waste disposal and spills of pollutants. In the United States and Europe, PDVSA’s operations are subject to various federal, state and local environmental laws and regulations, which may require them to take action to remedy or alleviate the effects on the environment of earlier plant decommissioning or leakage of pollutants.

PDVSA is taking important steps to prevent risks to the environment, people’s health, and the integrity of its installations. In 2003, PDVSA continued implementing its Integral Risk Management System (SIR-PDVSA®) throughout the company. The full deployment of this system is expected to be completed by 2006. This management system is based on international practices and standards, such as ISO 14001 for Environmental Management, ISO 18000 & British Standard BS 8800 for health and the Occupational Safety and Health Administration (OSHA)’s and American Petroleum Institute (API)’s 750 for process safety. In addition, PDVSA has an investment plan to comply with the applicable environmental regulations in Venezuela. This investment plan contemplates approximately $2,255 million in capital expenditure from 2004 through 2009, including the following: $1,150 million for product quality; $911 million for risk control at operating sites; $162 million for environmental compliance projects; and $32 million for other environmental-related investments. CITGO estimates expenditures of approximately $785 million for environmental and regulatory capital projects from 2004 through 2008. During 2003, PDVSA spent approximately $59 million in Venezuela and CITGO spent approximately $253 million for environmental and regulatory capital improvements in its operations.

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Additionally and as part of the environmental responsibility of PDVSA, there is a plan to remediate a total of 12,392 petroleum pits (excavations made on the soil surface to store oil sludge and / or drilling cuts). The plan has an expected duration of 12 years and started in 2001. As of December 2003, a total of 3,417 petroleum pits have been remediated. During the year ended December 31, 2003, the corporate management of PDVSA’s Safety, Health and Environment obtained detailed information that allowed determining the value of liabilities associated with the remediation of pits and other environmental damages. Accordingly, the Company’s management decided to record those commitments, which amount to $408 million, with a charge to 2003 results. The accrual for environmental issues as of December 31, 2003, is $473 million (see note 17).

During the work stoppage in December 2002 and the first months of 2003, there were oil spills which affected the environment in Venezuela. Two technical reports were prepared, one by INTEVEP (PDVSA’s Research and Development Center) and ICLAM (Maracaibo Lake Conservation Institute) and the other by Simón Bolívar University and IVIC (Venezuelan Scientific Investigations Institute). Both reports conclude that the impact of the oil spills were minor and were located principally in the Maracaibo Lake area. These conclusions were confirmed by the Ministry of Environment. The remediation costs for these minor oil spills were covered by the operating budget of the Western Operations Division of PDVSA (see note 21).

CITGO has received various notices of violation from the Environmental Protection Agency (EPA) and other regulatory agencies, which include notices under the federal Clean Air Act, and could be designated as Potentially Responsible Parties (“PRPs”) jointly with other industrial companies with respect to sites under the Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA). These notices are being reviewed and, in some cases, remedial action is being taken or CITGO is engaged in settlement negotiations.

Conditions that require additional expenditures may exist at various sites including, but not limited to, the Company’s operating complexes, service stations and crude oil and petroleum storage terminals. Management believes that these matters, in the normal course of operations, will not have a material effect on the financial position, liquidity or operations of PDVSA.

(21) Effects of the Work Stoppage on PDVSA

During December 2002 and the first months of 2003, a series of national events significantly interrupted the economic activities in Venezuela. Concurrently, a substantial group of workers from PDVSA and its Venezuelan subsidiaries abruptly initiated a work stoppage that interrupted the Company’s normal ongoing operations in Venezuela, that continued despite requests made by management of the Company in the local media for them to return to their positions. PDVSA is of the opinion that this interruption of the activities, and related actions, constituted sabotage, and accordingly the Company has referred the matter to the competent authorities, including the General Prosecutor of the Republic, to establish the corresponding responsibilities.

Management of PDVSA believes that this interruption, in the normal ongoing activities of PDVSA’s Venezuelan operations, was a major contributing factor to a significant reduction in PDVSA’s production volumes of oil and natural gas in 2003 and, to a lesser extent, to the reductions in production volumes experienced in 2002. Management attributes this reduction in crude oil and natural gas production as a major cause to the reduction in the exports of crude oil and products from Venezuela during 2003 and 2002. Presented below is a comparison of the export volumes and average price per barrel of exports of

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PDVSA’s principal Venezuelan subsidiary, PDVSA Petróleo, for the years ended December 31, 2003, 2002 and 2001:

Year	Export volumes of Crude oil and products	Average price per Barrel of exports
	(in thousands of barrels)	(US$ per barrel)
2003(*)	760,718	24.78
2002(*)	870,473	21.84
2001	1,026,271	20.14

(*) Work stoppage commenced in December 2002 and continued into 2003.

During the period that PDVSA’s operations were interrupted, the Venezuelan Government authorized PDVSA to purchase petroleum and diesel on the international market in order to meet the needs of the local market. These purchases were made at international prices that are higher than sales prices in the local market. The difference between the international purchase price for such petroleum products and the related sales prices realized in Venezuela resulted in an unfavorable effect for the Company in 2003 of approximately $504 million. Based upon an evaluation made by PDVSA, the Company’s upstream and downstream installations in Venezuela were also damaged by the work stoppage, resulting in losses of approximately $209 million. Both amounts are reflected in the results of operations in 2003.

As a result of the work stoppage and the extensive reduction in the Company’s workforce there were certain weaknesses in internal controls, which affected the processing of the Company’s financial and operational information during December 2002 and an important part of 2003. During the affected period, the Company concentrated its efforts on filling key managerial positions and hiring and training new personnel to take charge of information, financial, administrative and operating systems and on the implementation of alternative controls. Pre-existing controls have been progressively re-established.

(22) Subsequent Events

The most significant events considered, after the balance sheet, are summarized as follows:

(a) Funds Allocation for Social Programs

As part of the support to various social programs established by the National Government, during 2004 and part of 2005, the following activities have been carried out:

• At an Extraordinary Stockholder’s Meeting held on January 15, 2004, PDVSA approved the creation of Fondo de Inversíon Agrícola Zamora (Zamora Agricultural Investment Fund), with a partial contribution of up to $600 million, payable in bolivars. This Fund will be used to make payments for the execution of programs and projects relating to the country’s agricultural sector expressly indicated by the National Government through the Ministry of Agriculture and Lands, and with the involvement of public entities designated by this Ministry, which will act as executors through contacts of adhesion. The total contribution of $600 was made in 2004.

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• During an Extraordinary Stockholder’s Meeting held on January 23, 2004, PDVSA approved the creation of a fund aimed to honor the obligations acquired by CVP in connection with the execution of programs and projects for the development of educational, health, agricultural and industrial areas, together with highways and roads, among others. The fiduciary fund is named Fondo para el Desarrollo Económico y Social del País (FONDESPA), comprising extraordinary income, net of royalties and taxes provided by the export of crudes and byproducts exceeding the average price of $23 per barrel. This fund is comprised of an initial contribution of $1,000 million, and subsequent contributions of $250 million, and a contribution in bolivars equivalent to $1,042 million.

• During an Extraordinary Stockholder’s Meeting held on September 30, 2004, PDVSA approved the modification of CVP’s statutes for it to support social welfare activities. During 2004 and part of 2005, PDVSA has participated in various programs established by the National Government, by making contributions in bolivars from donations, and for social Missions (see note 18).

(b) Foreign Exchange Regime

On February 6, 2004, the National Government and the BCV superseded exchange agreement No. 2 of February 5, 2003, fixing the exchange rates for sales and purchases at Bs1,920.00 to $1 and Bs1,915.20 to $1, respectively. Also, the new agreement establishes the payment at the exchange rates set forth in the former agreement, for some purchase and sale operations pending payment and some operations in transit made by the exchange operators (see note 2).

On March 1, 2005, the National Government and the BCV superseded exchange agreement No. 2 dated February 6, 2004, fixing the exchange rates for sales and purchases at Bs2,150.00 to $1 and Bs2,144.60 to $1, respectively.

(c) Purchase of PDVSA Finance’s Debt

On June 28, 2004, PDVSA Finance made a public offer in cash for the purchase of a portion or the entirety of bonds issued by such entity. Simultaneously with this offer, the subsidiary asked for the consent of the bondholders to amend certain provisions of the Indenture and Supplemental Indentures, under which each series of bonds had been issued. The adoption of the amendments proposed required the consent of the majority of the bondholders of the main aggregated amount of each series owed by then, by voting for all of them as a single class. Bondholders with an aggregate approximating to 96.34% of the principal amount of the notes, participated in the offer and granted their consent in accordance with the purchase offer. According to this offer, on August 2, 2004 the subsidiary purchased a principal amount of such debt of $2,512 million (see note 14). Resulting from the repurchase of the notes, a premium of $54.8 million plus dealer/manager fees of $15.1 million and expenses of $1.7 million were charged to the 2004 results of operations.

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(d) Taxes and Contributions to the National Tax Authorities

On August 11, 2004, the Partial Reform Law of the Value Added Tax Law was published, reducing the rate applicable to the taxable base from 16% to 15%. This Law became effective on September 1, 2004 (see note 12 (d)).

On August 17, 2004, the Business Assets Tax Law of November 26, 1993 was repealed, effective September 1, 2004 (see note 12(c)).

In October 2004, the MEP established a new rate of royalties for the exploitation of extra-heavy crudes of the Orinoco Belt, carried out by the strategic associations, of 16-2/3 %, after October 11, 2004 (see notes 10(a) and 12(b)).

(e) Benefits to Workers

In December 2004, PDVSA signed a new collective labor contract, effective until 2006, whereby salary improvements and social benefits for the workers of the contractual payroll were introduced (see note 1(k)).

During 2005, the Company decided to incorporate approximately 5,300 workers, who worked formerly for contractor companies. Currently, the Company’s management is assessing the net effect of some contractual rights and benefits that might result from this decision.

(f) Transfer of Subsidiaries to Governmental Entities

In a Decree dated January 30, 2004, issued by the Presidency of the Bolivarian Republic of Venezuela and published in Official Gazette on February 2, 2004, the National Government approved the transfer of PDVSA’s ownership rights in the stock of Carbozulia to the Corporación de Desarrollo de la Región Zuliana (Corpozulia) (see note 7).

By presidential decree published in Official Gazette on January 21, 2005, it was decided to separate Pequiven, a subsidiary of PDVSA, for it to become Corporación Petroquímica de Venezuela attached to the Ministry of Basic Industries and Mining. The transformation of this subsidiary still requires a series of legal, financial and structural adjustments. The National Government has committed to guarantee the supply of raw materials by PDVSA, support the national petrochemical plan, promote the new Petrochemical Law, ensure the financing for new investments and accelerate the execution of projects. The terms for the transfer of such subsidiary have not been defined. The financial statements of Pequiven represent 5% of total assets as of December 31, 2003 and 2% of total revenues for the year then ended of the related consolidated totals in respect of PDVSA’s consolidated financial statements.

(g) Events that affect CITGO

CITGO received an informal inquiry from the Securities and Exchange Commission (“SEC”) seeking information from CITGO regarding an inquiry being conducted by a special commission of the Venezuelan National Assembly (the “VNA”), allegations made by a CITGO employee in a letter sent to both CITGO’s auditors as well as the SEC, and CITGO’s October 2004 tender offer

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for 11-3/8% senior notes. CITGO is cooperating and has provided the requested information to the SEC. On July 27, 2005, the VNA announced that it had concluded its inquiry. No claims of wrongdoing were made against CITGO or its directors, officers or employees as a result of the inquiry. In March 2005, a CITGO employee sent a memorandum to both CITGO’s auditors and the SEC referencing the VNA inquiry and matters related to CITGO’s internal audit department. An independent counsel investigation did not find any evidence of any acts or omissions that could have resulted in material misstatements in any of CITGO’s previously issued financial statements or any other acts or omissions by CITGO in violation of federal securities laws; however, they took note of, but did not address matters that were the subject of, pending internal reviews. These reviews involve payments beginning in 1999, a portion of which were made for the benefit of the Venezuelan Government which owns PDVSA, CITGO’s ultimate parent entity. These payments include scholarship payments made to several Venezuelan students, payments made to assist the Venezuelan Embassy in Washington, D.C. with building improvements and event costs, travel expenses paid on behalf of Venezuelan Government officials in connection with business conferences in the United States or visits to CITGO’s facilities, and payments for various cultural and charitable activities. The aggregate amount of such payments is not material in relation to the consolidated financial statements. CITGO is continuing to review those payments as well as their compliance with applicable law. A second independent counsel was retained to investigate the employee’s allegations regarding the management and integrity of the Company’s internal audit department. The second independent counsel concluded that there was no substance to such allegations.

(h) Energy Agreements/Covenants

Subsequent to December 31, 2003, the National Government entered into certain energy agreements with the governments of the following countries, mainly from Latin America and the Caribbean:

Country	Company	(MPBD)
Uruguay	ANCAP	43.80
Dominican Republic	REFIDOMSA	50.00
Argentina	CAMMESA	9.00
Paraguay	PETROPAR	24.66
Bolivia	YPFB	1.65
Jamaica	PETROJAM	21.00
Carribean countries	Various	27.60
Total		177.71

The agreements entered into with Caribbean countries include the following; Antigua and Barbuda, the Bahamas, Belize, Dominican Republic, Guyana, Saint Kitts and Nevis, Saint Vincent and the Grenadines, Santa Lucia and Suriname, which are members of the Energy Cooperation Agreement PETROCARIBE. These agreements are in the process of formalization and their terms are being negotiated.

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The agreement with the Dominican Republic was signed in November 2004, and revised in September 2005, through the participation of this country in the Energy Cooperation Agreement PETROCARIBE.

The agreement entered into with every country establishes that PDVSA will enter into a covenant for the supply of crude oil and refined products with the national oil company of each of these countries based on a number of barrels agreed by the Venezuelan Government.

These supply agreements provide for, among other conditions, a sale price equivalent to the market value, payment terms of between 30 and 90 days for a significant portion of every shipment, and a long-term financing of the remaining portion (between 15 and 20 years). The agreements will be effective for one year, and may be extended by mutual agreement of the parties involved.

In accordance with an agreement subscribed in 2000, PDVSA supplied 53 MBPD of crude oil to Cuba. In 2004 this agreement was modified to supply 92 MBPD of crude oil.

(i) New Central Bank Law

A new Central Bank Law came into effect in July 2005, which establishes a new regime for PDVSA’s foreign currency transactions. According to this new regime, PDVSA will only be obligated to sell to the BCV the foreign currency revenues necessary to meet its local currency obligations. The remaining foreign currency amounts can be held by PDVSA in order to meet its foreign currency obligations and investments. Any amount in excess of the above shall be transferred by PDVSA to a Fund created by the Executive Branch. For the implementation of this new regime, a new exchange agreement between the Ministry of Finance and the BCV is currently under consideration.

(j) Refineries Affected by Recent Hurricanes

During the months of August and September 2005, some hurricanes affected the Caribbean area and the Gulf Coast and East Coast of The United States of America. As a result of these natural events, the activities of some of the refineries operated by PDVSA’s subsidiaries have been interrupted and operations are expected to be resumed during the next weeks. Estimated damages to PDVSA’s installations are not considered significant in relation to the consolidated financial statements of PDVSA.

(k) Reporting Requirements Pursuant to the Indenture

Pursuant to the terms of the senior indenture, dated as of May 14, 1998 between the Company’s finance subsidiary, PDVSA Finance, and J.P. Morgan Chase Bank (formerly, “The Chase Manhattan Bank”), as Trustee (the “Trustee”), as supplemented, PDVSA Finance is required to provide audited financial statements to the Trustee within 180 days after year-end. On June 30, 2005, PDVSA Finance provided to the Trustee its annual audited financial statements for the fiscal year ended December 31, 2004, prepared in accordance with International Financial Reporting Standards (IFRS) (formerly International Accounting Standards or IAS) adopted by the International Accounting Standards Board.

As part of the continuing review of PDVSA Finance’s financial statements by management and the Company’s Independent Registered Public Accounting Firm, it has been identified that

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approximately US$72 million was paid by PDVSA Petróleo in respect of expenses and premiums in connection with PDVSA Finance’s cash tender offer that should have been recorded in PDVSA Finance’s financial statements for the fiscal year ended December 31, 2004 as an expense of PDVSA Finance with a corresponding contribution from PDVSA to PDVSA Finance. Accordingly, we have been advised that the audit opinion with respect to PDVSA Finance’s financial statements for the fiscal year ended December 31, 2004 will be retracted and that such financial statements should be restated to reflect such expense and corresponding contribution.

It is unclear whether such restatement of PDVSA Finance’s financial statements for the year ended December 31, 2004 previously provided to the Trustee on a timely basis would constitute an event of default under the terms of the senior indenture, as supplemented, which occurred subsequent to December 31, 2003. Nonetheless, the Company and its legal counsel are of the opinion that any event of default that may result from such restatement would be cured upon the delivery of the restated financial statements to the Trustee. The Company is currently in the process of completing the restatement of PDVSA Finance’s financial statements for the fiscal quarter ended September 30, 2004 and for the fiscal year ended December 31, 2004. The Company intends to deliver such restated financial statements of PDVSA Finance to the Trustee promptly after its completion and, in any event, within 60 days.

In addition to the annual financial statements of PDVSA Finance, the senior indenture, as supplemented, requires the Company to deliver unaudited quarterly financial statements of PDVSA Finance to the Trustee within 90 days of the first three quarters of each year. As of the date of this report the Company is in the process of finalizing the unaudited financial statements for the quarter ended June 30, 2005, and accordingly has not delivered such to the Trustee within the 90 day requirement. The Company intends to deliver the unaudited financial statements for the quarter ended June 30, 2005 to the Trustee promptly after its completion with any event of default arising from such late submission being cured upon such presentation to the Trustee.

(l) Recently Issued Accounting Standards

During 2004 and 2005 new accounting standards were issued that include, among others:

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and the characterization of mineral rights as intangible assets in statements 141 and 142. The guidance in this FSP should be applied to the first reporting period beginning after April 29, 2004.

In October 2004, the FASB’s Emerging Issues Task Force issued EITF Abstract EITF 04-1, “Accounting for Preexisting Relationships between the Parties to a Business Combination”. This Issue applies when two parties that have a preexisting relationship enter into a business combination. Specifically, the Issue is whether a consummation of a business combination between two parties that have a preexisting relationship should be evaluated to determine if a settlement of a preexisting relationship exists, and the accounting for the preexisting relationship. PDVSA is in the process of analyzing the effects of this statement.

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(23) Supplementary Information on Oil and Gas Exploration and Production Activities (Unaudited)

The following tables provide supplementary information on the oil and gas exploration, development and production activities in compliance with SFAS No. 69 “Disclosures about Oil and Gas Producing Activities”, published by the U.S. Financial Accounting Standards Board. All exploration and production activities are located in Venezuela, principally represented by PDVSA Petróleo and its subsidiaries and PDVSA Gas.

Table I - Crude Oil and Natural Gas Reserves

All the crude oil and natural gas reserves located in Venezuela are owned by the Bolivarian Republic of Venezuela. Crude oil and natural gas reserves are estimated by PDVSA and reviewed by the Ministry of Energy and Mines, using reserve criteria which are consistent with those prescribed by the American Petroleum Institute (API) and the U.S. Securities and Exchange Commission (SEC).

Proved reserves are the estimated quantities of crude oil and natural gas which, with reasonable certainty, are recoverable in future years from known deposits under existing economic and operating conditions. Due to the inherent uncertainties and limited nature of the data relating to deposits, estimates of underground reserves are subject to change over time, as additional information becomes available. Proved reserves do not include additional quantities which may result from the extension of currently explored areas, or from the application of secondary recovery processes not yet tested and determined to be economically feasible.

Proved developed reserves are the quantities that can be expected to be recovered from existing wells with existing equipment and operating methods. Proved undeveloped reserves are those volumes which are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Proved crude oil reserves have been separated between conventional crude oils, consisting of light, medium and heavy grade crude oils, and extra-heavy crude oil.

A summary of the annual changes in the proved reserves of crude oil and natural gas follows:

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(a) Conventional and Extra-heavy Crude Oil Reserves (in millions of barrels):

	Years ended December 31
	2003		2002		2001

Proved developed and undeveloped reserves of light, medium and heavy crude oil at January 1	41,776		42,225		41,998
Revisions	589		238		784
Extensions and new discoveries	433		238		538
Production	(844	)	(925	)	(1,095	)
Proved developed and undeveloped reserves of light, medium and heavy crude oil at December 31	41,954		41,776		42,225
Proved developed and undeveloped reserves of extra-heavy crude oil at December 31	35,186		35,381		35,558
Total proved developed and undeveloped reserves at December 31	77,140		77,157		77,783
Total proved developed reserves, submitted to production, including extra-heavy crude oil at December 31 (included above)	16,288		15,699		17,372

At December 31 2003, 2002 and 2001, proved reserves of crude oil under operating agreements amounted to 5,446 million barrels, 5,501 million barrels and 5,600 million barrels, respectively (see note 10 (c)). During 2003, 2002 and 2001, the daily production of crude oil in the areas under operating agreements was approximately 465,400 barrels, 481,000 barrels and 502,000 barrels, respectively.

Venezuela has significant reserves of extra-heavy crude (less than 8 API degrees), which are being developed in conjunction with the production of Orimulsión® by the subsidiary BITOR, through operating agreements which apply new technologies for refining and improvement of the crude oil aimed at the economic viability of production. PDVSA used 22 million, 25 million and 27 million barrels of extra-heavy crude oil for the production of Orimulsión® during 2003, 2002 and 2001, respectively. Furthermore, PDVSA is currently developing Venezuela’s significant extra-heavy crude oil reserves with several foreign companies through joint ventures (see note 10 (a)).

During the years ended December 31, 2003, 2002 and 2001, the changes in proved developed and undeveloped extra-heavy crude oil reserves related to these projects and total proved developed and undeveloped extra-heavy crude oil reserves at those dates, reflecting the full amount of the reserves, are summarized below (in millions of barrels):

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	2003				2002				2001
	Projects		Total including projects		Projects		Total including projects		Projects		Total including projects
Proved developed and undeveloped reserves of extra-heavy crude oil at January 1	10,639		35,381		10,768		35,558		9,776		35,688
Revisions(1)	—		—		—		—		1,079		—
Production	(156	)	(195	)	(129	)	(177	)	(87	)	(130	)
Proved developed and undeveloped reserves of extra-heavy crude oil at December 31	10,483		35,186		10,639		35,381		10,768		35,558
Proved developed extra-heavy crude oil reserves at December 31	1,751		3,010		1,273		2,154		1,170		1,963
Net proved extra-heavy crude oil reserves in unincorporated joint ventures at December 31	7,916				8,224				8,121
Net proved extra-heavy crude oil reserves in equity affiliate at December 31 (2)	2,567				2,415				2,647
	10,483				10,639				10,768

(1) Includes transfers from unassigned areas.

(2) Represents PDVSA’s equity share of the Petrozuata extra-heavy oil joint venture.

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(b) Natural Gas Reserves:

	2003		2002		2001
	Billions of cubic feet (BCF)

Proved developed and undeveloped reserves of natural gas at January 1	134,655		135,819		135,080
Revisions	2,358		468		997
Extensions and new discoveries	1,984		—		1,209
Production	(1,381	)	(1,632	)	(1,467	)

Proved developed and undeveloped reserves of natural gas at December 31	137,616		134,655		135,819
Proved reserves related to extra-heavy crude reserves at December 31	12,427		12,454		12,476
Total proved developed and undeveloped reserves at December 31	150,043		147,109		148,295

Total proved developed reserves of natural gas, submitted to production, including quantities associated with extra-heavy crude oil in production at December 31 (included above)	105,030		102,191		103,807

Proved natural gas reserves include the portion of liquefiable natural hydrocarbons recoverable in PDVSA’s processing plants. In 2003, 2002 and 2001, natural gas liquids recovered amounted to some 52 million barrels, 63 million barrels and 63 million barrels, respectively.

Production of natural gas is shown on the basis of actual volumes before the extraction of liquefiable hydrocarbons. During 2003, 2002 and 2001, natural gas utilized in reinjection operations amounted to 900 BCF, 638 BCF and 695 BCF, respectively.

Table II – Costs Incurred in Exploration and Development Activities

Exploration costs include the costs of geological and geophysical activities and drilling and equipping exploratory wells. Development costs include those of drilling and equipping development wells, enhanced recovery projects and facilities to extract, treat and store crude oil and natural gas. Annual costs, summarized below, include amounts both expensed and capitalized for PDVSA’s conventional and extra-heavy crude oil reserves (in millions of dollars):

F-71

	2003				2002					2001
	Conventional reserves	Extra- heavy crude oil reserves		Total	Conventional reserves	Extra- heavy crude oil reserves		Total		Conventional reserves	Extra- heavy crude oil reserves		Total
Exploration costs	27	—		27	133	—		133		174	—		174
Development costs	629	250	(2)	879	1,434	510	(2)	1,944		1,364	792	(2)	2,156
Total	656	250		906	1,567	510		2,077		1,538	792		2,330
Equity affiliate(1)	—	13		13	—	(19	)	(19	)	—	86		86
Total	656	263		919	1,567	491		2,058		1,538	878		2,416

(1) Represents PDVSA’s equity share of the Petrozuata extra-heavy oil joint venture.

(2) Represents PDVSA’s proportional share in unincorporated extra-heavy oil joint ventures.

Table III – Capitalized Costs Relating to Oil and Gas Producing Activities

The following table summarizes capitalized costs of oil and gas exploration and production activities and the related accumulated depreciation and depletion at December 31 for PDVSA’s conventional and extra-heavy crude oil reserves (in millions of dollars):

	2003						2002						2001
	Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total			Conventional reserves		Extra- heavy crude oil reserves		Total
Producing assets(1)	30,111		2,788		32,899		32,486		2,638		35,124			31,255		1,038		32,293
Support facilities	16,204		57		16,261		12,681		16		12,697			12,657		5		12,662
Total	46,315		2,845		49,160		45,167		2,654		47,821			43,912		1,043		44,955

Accumulated depreciation and depletion	(28,940	)	(419	)	(29,359	)	(26,625	)	(239	)	(26,864	)		(25,720	)	(43	)	(25,763	)
Construction in progress	2,027		632		2,659		2,546		573		3,119			3,092		1,674		4,766
Net capitalized costs	19,402		3,058		22,460		21,088		2,988		24,076			21,284		2,674		23,958
Equity affiliate(2)	—		1,388		1,388		—		1,375		1,375			—		1,394		1,394
Total	19,402		4,446		23,848		21,088		4,363		25,451			21,284		4,068		25,352

(1) Includes land of $135 million, $139 million and $139 million at December 31, 2003, 2002 and 2001, respectively.

(2) Represents PDVSA’s share of the Petrozuata extra-heavy oil joint venture.

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Table IV – Results of Operations for Oil and Gas Producing Activities for Each Year (expressed in millions of dollars):

	2003						2002						2001
	Conventional reserves		Extra-heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra-heavy crude oil reserves		Total
Revenues from production:
Sales	14,759		981		15,740		13,479		633		14,112		14,091		254		14,345
Transfers	7,619		—		7,619		8,322		—		8,322		8,931		—		8,931
Production costs	(4,306	)	(154	)	(4,460	)	(4,824	)	(135	)	(4,959	)	(4,888	)	(76	)	(4,964	)
Production tax	(6,267	)	(31	)	(6,298	)	(5,642	)	(17	)	(5,659	)	(3,701	)	(32	)	(3,733	)
Depreciation and depletion	(1,665	)	(177	)	(1,842	)	(1,882	)	(165	)	(2,047	)	(1,479	)	(25	)	(1,504	)
Exploration costs	(27	)	—		(27	)	(133	)	—		(133	)	(174	)	—		(174	)
Results before income taxes	10,113		619		10,732		9,320		316		9,636		12,780		121		12,901
Income taxes	(4,926	)	(79	)	(5,005	)	(4,494	)	(17	)	(4,511	)	(8,218	)	—		(8,218	)
Results from production operations	5,187		540		5,727		4,826		299		5,125		4,562		121		4,683
Equity affiliate(1)	—		125		125		—		213		213		—		114		114
Total	5,187		665		5,852		4,826		512		5,338		4,562		235		4,797

(1) Represents PDVSA’s equity share of the Petrozuata extra-heavy oil joint venture.

Revenues from crude oil production are calculated using market prices as if all production were sold.

The difference between the results before income taxes referred to above (Conventional Reserves) and the operating income reported for the upstream segment in note 19 for the years ended 2003, 2002 and 2001, is mainly due to: (1) the use of transfer prices for segment reporting purposes and market prices in the results of operations, and the reclassification of sales of gas to the downstream operations segment of some $1,138 million, $2,870 million and $2,796 million, respectively; (2) the inclusion in the business segment of general expenses and other of some $1,274 million, $2,734 million and $2,061 million, respectively and; (3) certain intercompany charges of some $391 million during 2001, recognized only for segment reporting purposes.

Production costs are lifting costs incurred to operate and maintain productive wells and related equipment and facilities, including such costs as operating labor, materials, supplies, fuel consumed in operations and the costs of operating natural liquid gas plants. Production costs also include administrative expenses and depreciation and depletion of equipment associated with production activities. In addition, they include operating fees for certain fields operated by specialized companies under operating agreements.

F-73

Production costs include $2,345 million, $2,174 million and $2,110 million, paid to independent contractors under service contracts during 2003, 2002 and 2001, respectively, which relate to the production of 170 million, 176 million and 183 million barrels of crude oil during 2003, 2002 and 2001, respectively.

The costs of extra-heavy crude production include the expenses incurred to operate and maintain the productive wells, as well as transportation and handling expenses.

Exploration costs include those related to the geological and geophysical activities and non-productive exploratory wells. Depreciation and depletion expenses relate to assets employed in exploration and development activities. Income tax expense is calculated using the statutory rate for the year. For these purposes, results of operations do not include financing expenses and corporate overhead nor their associated tax effects.

The following table summarizes average per unit sales prices and production costs for the years ended December 31 (in dollars):

	2003	2002	2001
Average sales price:
Crude oil, per barrel	24.35	21.19	18.95
Natural gas liquids, per barrel	18.84	17.65	19.55
Natural gas, per barrel	3.20	4.34	5.35
Average production costs, per barrel of oil equivalent	3.85	3.92	3.38
Average production costs, per barrel of oil equivalent, excluding operating agreements	2.06	2.42	2.17

Table V - Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves

Due to uncertainties surrounding the timing of the ultimate development of the country’s extra-heavy crude oil reserves, only the conventional proved reserves and those reserves related to PDVSA’s participation in the extra-heavy crude oil projects have been used in the calculation of discounted future net cash flows.

Estimated future cash inflows from production are computed by applying year-end prices for oil and gas to year-end quantities of estimated proved reserves. Future income from extra-heavy crude oil production is determined using prices and quantities of the upgraded crude that will be produced in the upgrading facilities. Upgraded crude oil prices approximate those of conventional crude oil with similar characteristics at year-end. Future development and production costs are those estimated future expenditures necessary to develop and produce year-end estimated proved reserves, assuming continuation of year-end economic conditions. Estimated future income tax expense is calculated by applying the appropriate year-end statutory tax rates. These rates reflect allowable deductions and tax credits and are applied to estimated future pre-tax net cash flows. This calculation requires a year-by-year estimate of when future expenditures will be incurred and when the reserves will be produced.

The information provided below does not represent certified estimates of PDVSA’s expected future cash flows or a precise value of its proved measured crude oil and gas reserves. Estimates of proved reserves

F-74

are imprecise and may change over time as new information becomes available. Furthermore, probable and possible reserves, which may become proved in the future, are excluded from the calculation. The valuation to comply with SFAS No. 69 requires assumptions as to the timing of future production from proved reserves and the timing and amount of future development and production costs. The calculations are made as of December 31 of each year and should not be relied upon as an indication of PDVSA’s future cash flows or the value of the oil and gas reserves (in millions of dollars):

	2003						2002						2001
	Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total
Future cash inflows	1,182,623		78,217		1,260,840		1,091,423		64,524		1,155,947		893,878		27,364		921,242
Future production costs	(152,471	)	(11,227	)	(163,698	)	(212,869	)	(10,018	)	(222,887	)	(187,727	)	(7,108	)	(194,835	)
Future production taxes	(336,354	)	(12,007	)	(348,361	)	(308,413	)	(9,156	)	(317,569	)	(251,816	)	(3,418	)	(255,234	)
Future development costs	(54,726	)	(6,196	)	(60,922	)	(74,130	)	(4,952	)	(79,082	)	(60,136	)	(2,220	)	(62,356	)
Future income tax expense	(286,707	)	(14,668	)	(301,375	)	(220,483	)	(11,322	)	(231,805	)	(179,962	)	(3,918	)	(183,880	)
Cost of asset retirements	(2,596	)	—		(2,596	)	—		—		—		—		—		—
Future net cash flows	349,769		34,119		383,888		275,528		29,076		304,604		214,237		10,700		224,937
Effect of discounting net cash flows at 12% (10% at December 31, 2002 and 2001)	(285,354	)	(27,830	)	(313,184	)	(223,588	)	(23,643	)	(247,231	)	(172,961	)	(7,881	)	(180,842	)
Discounted future net cash flows	64,415		6,289		70,704		51,940		5,433		57,373		41,276		2,819		44,095
Equity affiliate(1)	—		1,629		1,629		—		2,064		2,064		—		1,124		1,124
Total	64,415		7,918		72,333		51,940		7,497		59,437		41,276		3,943		45,219

(1) Represents PDVSA’s equity share of the Petrozuata extra-heavy oil joint venture.

F-75

Table VI - Analysis of Changes in the Standardized Measure of Discounted Future Net Cash Flows Related to Proved Crude Oil and Natural Gas Reserves

The following table analyzes the changes as of December 31 of each year (in millions of dollars):

	2003						2002						2001
	Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total		Conventional reserves		Extra- heavy crude oil reserves		Total
Present value at January 1,
Sales, net of production costs and taxes	(11,812	)	(509	)	(12,321	)	(12,762	)	(63	)	(12,825	)	(11,446	)	(60	)	(11,506	)
Value of reserves added during the year due to extensions and discoveries	451		—		451		—		—		—		902		1,229		2,131
	(11,361	)	(509	)	(11,870	)	(12,762	)	(63	)	(12,825	)	(10,544	)	1,169		(9,375	)
Change in value of previous year reserves due to:
Development costs incurred during the year	629		250		879		—		—		—		1,365		792		2,157
Change in future development costs	(3,480	)	(91	)	(3,571	)	13,994		—		13,994		2,272		(317	)	1,955
Net changes in prices and production costs	24,078		1,819		25,897		23,943		(4	)	23,939		(81,216	)	(3,887	)	(85,103	)
Revisions of previous reserve estimates	4,429		6		4,435		(3,215	)	(1	)	(3,216	)	1,161		—		1,161
Net changes in income taxes	(12,196	)	5		(12,191	)	(8,301	)	—		(8,301	)	61,642		1,012		62,654
Net changes in production rates and other	10,376		(624	)	9,752		(2,994	)	70		(2,924	)	(9,354	)	498		(8,856	)
Total change during the year	12,475		856		13,331		10,665		2		10,667		(34,674	)	(733	)	(35,407	)
Equity affiliate(1)	—		(435	)	(435	)	—		(915	)	(915	)	—		(915	)	(915	)
Total	12,475		421		12,896		10,665		(913	)	9,752		(34,674	)	(1,648	)	(36,322	)

(1) Represents PDVSA’s equity share of the Petrozuata extra-heavy oil joint venture.

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Item 19. Exhibits

Exhibit No:		Description

Exhibit 1.1		Memorandum and articles of association of PDVSA (incorporated herein by referece to the Registration Statement on Form F-1 filed by us on June 2, 1993).

Exhibit 12.1*		Certification of the Principal Executive Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities and Exchange Act of 1934.

Exhibit 12.2*		Certification of the Principal Financial Officer required by Rule 13a-14(a) or Rule 15d-14(a) of the Securities and Exchange Act of 1934.

Exhibit 13.1*		Certification of the Principal Executive Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Securities and Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).

Exhibit 13.2*		Certification of the Principal Financial Officer required by Rule 13a-14(b) or Rule 15d-14(b) of the Securities and Exchange Act of 1934 and Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350).

Exhibit 14.1		Annual Report on Form 20-F of PDVSA Finance Ltd. for the year ended December 31, 2003 as first filed with the U.S. Securities and Exchange Commission (Commission file No. 333-09678) on October 7, 2005 (incorporated herein by reference).

*Filed Herewith

SIGNATURES

The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.

	PDVSA, S.A.

	By:	/s/ Rafael Ramírez Carreño
		Name: Rafael Ramírez Carreño
		Title: President

Date: October 7, 2005

ANNEX A

Measurement Conversion Table

1 barrel	=	42 U.S. gallons

1 barrel of oil equivalent	=	1 barrel of crude oil	=	5,800 cubic feet of gas (based on the actual average equivalent energy content of PDVSA’s proved natural gas reserves)

1 barrel of crude oil per day	=	Approximately 50 tons of crude oil per year

1 cubic meter	=	33.315 cubic feet

1 metric ton	=	1,000 kilograms	=	Approximately 2,205 pounds

1 metric ton of crude oil	=	Approximately 7.3 barrels of crude oil (assuming a specific gravity of 33º)

1 metric ton of oil equivalent	=	Approximately 1,125 cubic meters of natural gas

A-1

Glossary of Certain Oil and Gas Terms

Unless the context indicates otherwise, the following terms used in this report have the meanings set forth below:

2D		Two dimensional seismic lines (km).

3D		Three dimensional seismic lines (square kilometers).

4D		Three dimensional seismic lines (square kilometers) taken as different periods of time.

Alkylation		The process of producing alkilates (refined products used to enhance gasoline).

AQUACONVERSION®		A proprietary technology for the thermal/catalytic conversion of heavy crude oil and residuals by treatment with steam and additives, to reduce the viscosity of heavy crude oil fractions and residuals.

API gravity		An indication of density of crude oil or other liquid hydrocarbons as measured by a system recommended by the American Petroleum Institute (API), measured in degrees. The lower the API gravity, the heavier the compound. For example, asphalt has an API gravity of 8° and gasoline has an API gravity of 50°.

Barrels (or bbl)		Barrels of crude oil, including condensate and natural gas liquids.

BCF		Billions of cubic feet.

BOE		Barrels of oil equivalent.

BPD		Barrels per day.

Cetane index		An index used to measure diesel quality based on the efficiency with which the fuel ignites; the higher the number the higher the quality of the diesel.

Condensate		Light carbon substances produced from natural gas that condense into liquid at normal temperatures and pressures associated with surface production equipment.

Crude oil		Crude oil containing condensate.

Crude slate (or slate)		A listing of the various crudes that are processed in a refinery during a given period in a given configuration.

Distillate		Liquid hydrocarbons distilled from crude or condensate.

Extra-heavy crude oil		Crude oil with an average API gravity of less than 11°.

FCC		The FCC unit is the basis of modern refineries. It “cracks” heavy molecules of crude oils into smaller, lighter ones that can then be used in the formulation of gasolines.

Feedstocks		Partially refined petroleum that is added to the crude slate and converted into refined petroleum products.

A-2

Fractionator		A processing unit that breaks down feedstocks into desired fractions (specific boiling ranges).

Heavy crude oil		Crude oil with an average API gravity of less than 21°.

Hydrotreatment		The process of removing sulfur from a hydrocarbon stream in the presence of a catalyst.

km		Kilometer.

Light crude oil		Crude oil with an average API gravity of 30° or more.

LNG		Liquefied natural gas.

Medium crude oil		Crude oil with an average API gravity of 21° or more and less than 30°.

MBPD		Thousands of barrels per day.

MCF		Thousands of cubic feet.

MCFD		Thousands of cubic feet per day.

MDWT		Thousand deadweight tons; a designation for the size or displacement of a ship.

M3D		Cubic meters per day.

MM3D		One thousand cubic meters per day.

MMB		Millions of barrels.

MMMB		Billions of barrels.

MMCFD		Millions of cubic feet per day.

Olefins		A class of unsaturated hydrocarbons.

Pitch		Black or dark viscose substance obtained as a residual in the distillation of oil (bituminous—resin).

Proved reserves		Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reserves under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not escalations based upon future conditions.

A-3

Proved developed reserves		Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Additional oil and gas expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing natural forces and mechanisms of primary recovery are included as “proved developed reserves” only after testing by a pilot project or after the operating of an installed program has confirmed through production response that increased recovery will be achieved.

Proved undeveloped reserves		Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively minor expenditure is required for recompletion, but does not include reserves attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proven to be effective by actual testing in the area and in the same reservoir. Reserves on undrilled acreage are limited to those drilling units offsetting productive units that are reasonably certain of production when drilled. Proved reserves for other undrilled units can be claimed only where it can be demonstrated with certainty that there is continuity of production from the existing productive field.

Reformer		A processing unit that converts naphtha into higher octane components.

Spud		To begin to drill a well.

A-4